The Energy & Minerals Group 2016 Annual Meeting September 21, 2016
Cautionary Statements This presentation contains forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. In particular, statements, express or implied, concerning future actions, conditions or events, future operating results or the ability to generate revenues, income or cash flow or to make distributions or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations of Tallgrass Energy Partners, LP, Tallgrass Energy GP, LP or Rockies Express Pipeline LLC and their respective affiliates may differ materially from those expressed in these forwardlooking statements. Many of the factors that will determine these results are beyond Tallgrass Energy Partners, LP s, Tallgrass Energy GP, LP s and Rockies Express Pipeline LLC s ability to control or predict and are necessarily based upon various assumptions involving judgements with respect to the future. Forward-looking statements contained in this presentation specifically include, without limitation, the forecast and other projected future results of Tallgrass Energy Partners, LP and Rockies Express Pipeline LLC, including assumptions incorporated into such projections, the expected benefits to Tallgrass Energy Partners, LP as a result of its acquisition of a 25 percent interest in Rockies Express Pipeline LLC, the feasibility, cost and execution timing of capital and other growth projects at Rockies Express Pipeline LLC and Tallgrass Energy Partners, LP, the stability of future cash flows at Tallgrass Energy Partners, LP and expectations regarding price and volume risk, future dropdown transactions, and assumptions about Tallgrass Energy Partners, LP and Rockies Express Pipeline LLC s future credit profile and operating and financial results. These statements also include, among others, Tallgrass Energy Partners, LP s, Tallgrass Energy GP, LP s and Rockies Express Pipeline LLC s respective ability to complete and integrate acquisitions, implement their respective business plans and complete internal growth projects; changes in general economic conditions; competitive conditions; actions taken by third-party operators, processors and transporters; demand for natural gas transportation, storage and processing services and crude oil transportation services; price and availability of debt and equity financing; availability and price of natural gas and crude oil compared to alternative fuels; energy efficiency and technology trends; operating hazards and other risks incidental to the business; natural disasters, weather-related delays and casualty losses; interest rates; labor relations; customer defaults; changes in tax status; effects of existing and future laws and governmental regulations; effects of future litigation; and other uncertainties. There is no assurance that any of the actions, events or results of the forward-looking statements will occur, or if any of them do, what impact they will have on our results of operations or financial condition. Because of these uncertainties, you are cautioned not to put undue reliance on any forward-looking statement. This presentation does not constitute an offer to sell any securities of Tallgrass Energy Partners, LP, Tallgrass Energy GP, LP or their respective affiliates or a solicitation of an offer to buy any securities of Tallgrass Energy Partners, LP, Tallgrass Energy GP, LP, or their respective affiliates. 2
Non-GAAP Measures Adjusted EBITDA and Distributable Cash Flow are non-gaap supplemental financial measures that management and external users of our consolidated financial statements and financial statements of our subsidiaries and unconsolidated investments, such as industry analysts, investors, lenders and rating agencies, may use to assess: Our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or, in the case of Adjusted EBITDA, financing methods; The ability of our assets to generate sufficient cash flow to make distributions to our unitholders; Our ability to incur and service debt and fund capital expenditures; and The viability of acquisitions and other capital expenditure projects and the returns on investment of various expansion and growth opportunities. Management believes that the presentation of Adjusted EBITDA and Distributable Cash Flow in this presentation provides useful information to investors in assessing our financial condition and results of operations. Adjusted EBITDA and Distributable Cash Flow should not be considered alternatives to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP, nor should Adjusted EBITDA and Distributable Cash Flow be considered alternatives to available cash, operating surplus, distributions of available cash from operating surplus or other definitions in Tallgrass Energy Partners, LP s partnership agreement. Adjusted EBITDA and Distributable Cash Flow have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. Additionally, because Adjusted EBITDA and Distributable Cash Flow may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility. We generally define Adjusted EBITDA as net income excluding the impact of interest, income taxes, depreciation and amortization, noncash income or loss related to derivative instruments, non-cash long-term compensation expense, impairment losses, gains or losses on asset or business disposals or acquisitions, gains or losses on the repurchase, redemption or early retirement of debt, and earnings from unconsolidated investments, but including the impact of distributions from unconsolidated investments. We generally define Distributable Cash Flow as Adjusted EBITDA, plus preferred distributions received from Pony Express in excess of its distributable cash flow attributable to our net interest and adjusted for deficiency payments received from or utilized by Pony Express shippers, less cash interest expense, maintenance capital expenditures, distributions to noncontrolling interests in excess of earnings allocated to noncontrolling interests, and certain cash reserves permitted by our partnership agreement. For a reconciliation of these non-gaap measures to their most directly comparable GAAP financial measures, please see Adjusted EBITDA and Distributable Cash Flow Reconciliation. 3
Tallgrass Energy Overview 4
Tallgrass Energy Overview Two operating partnerships with distinct functions make up the Tallgrass platform which allows Tallgrass to develop assets at TDEV TDEV Tallgrass Development (Private) TEP Tallgrass Energy Partners (NYSE:TEP) ASSET INCUBATOR Private partnership Formed by management, Kelso, and EMG Acquired assets from Kinder Morgan in November 2012 Current holdings 50% interest in Rockies Express Pipeline ( REX ) Receives REX management fee (1% of REX EBITDA) 2% interest in Pony Express Pipeline ( Pony ) 100% interest in Tallgrass Terminals ( Terminals ) ~9.3 million TEP units (3) LONG-TERM OPERATING VEHICLE Public partnership $313 million IPO in May 2013 ~$2.2 billion of dropdown acquisitions from TDEV ~$0.5 billion of 3 rd party acquisitions Current holdings Tallgrass Interstate Gas Transmission ( TIGT ) Tallgrass Midstream ( TMID ) Trailblazer Pipeline ( Trailblazer ) BNN Water Solutions ( BNN ) 98% interest in Pony Express Pipeline ( Pony ) 25% interest in Rockies Express Pipeline ( REX ) Consolidated Footprint Opal Kanda Wamsutter Casper Douglas Guernsey TALLGRASS DEVELOPMENT (TDEV, Private) REX Pipeline (50% ownership) Lease of Overthrust Pipeline Capacity (1) Pony Pipeline (2% ownership) Oil Storage Terminal Cheyenne Meeker Texas footprint BNN Water Solutions Sterling Terminal Beatrice Lebanon Clarington BNN Big Lake Project (Reagan County) BNN Effluent Business (Karnes City) Ponca City Refinery Cushing Terminal (2) TALLGRASS ENERGY PARTNERS (NYSE:TEP) Tallgrass Interstate Gas Transmission Trailblazer Pipeline Pony Pipeline (98% ownership) REX Pipeline (25% ownership) Lease of Overthrust Pipeline Capacity (1) Tallgrass Midstream BNN Water Solutions (1) Overthrust Pipeline is owned by Questar and consists of 255 miles of pipeline. (2) Tallgrass Terminals owns 20% of a joint venture, which owns and operates an oil terminal facility in Cushing, OK, and 100% of the Sterling and Buckingham Terminals. (3) As of July 21, 2016. 5
Summary Ownership Structure (3) TEP Owners LP Ownership % Management, EMG & Kelso (1) Public 59% TDEV 13% Tallgrass Equity 28% Class B Shares Tallgrass Equity Ownership % Public (TEGP) 30% Management 17% EMG & Kelso 53% Tallgrass Development, LP Tallgrass Development or TDEV Tallgrass Energy GP, LP NYSE: TEGP Class A Shares Public TEGP Shareholders 50% (2) 100% REX Terminals LP Units Tallgrass Equity Units Tallgrass Equity Units Tallgrass Equity, LLC Tallgrass Equity GP Equity Value: ~$2.8 billion (4) 2% Pony 20 million LP Units GP interest and IDRs Tallgrass Energy Partners, LP NYSE: TEP Market Cap: ~$3.2 billion (4) LP Units Public TEP Unitholders 98% Crude Oil Transportation and Logistics Segment Pony 100% Natural Gas Transportation and Logistics Segment TIGT Processing and Logistics Segment TMID 100% 100% Trailblazer BNN 100% 25% (2) REX (1) Kelso & Company ( Kelso ), the Energy & Minerals Group ( EMG ) and Tallgrass KC, LLC, an entity owned by management, hold an exchange right which allows them to exchange one Tallgrass Equity unit and one Class B share for one Class A share. An affiliate of Magnetar Capital also owns an approximate 10% limited partner interest in TDEV. (2) Phillips 66 owns the remaining 25% of REX. (3) As of 7/29/2016. (4) As of 9/13/2016. Equity value of Tallgrass Equity represents ~157 million Tallgrass Equity units at TEGP share price as of 9/13/16 less the market value of 20 million TEP units held by Tallgrass Equity. 6
Tallgrass Execution 7
Q2 2016 Financial and Operational Update TEP Financial Update ($ in millions) Q2 2016 Adjusted EBITDA $114 Distributable Cash Flow $112 Coverage Ratio 1.41x Leverage Ratio 2.7x (1) Senior Notes Offering TEP closed an offering of $400mm of 5.50% senior unsecured notes due 2024 on September 1, 2016 Operational Update Rockies Express Pipeline TEP acquired a 25% interest in REX from Sempra for ~$440mm in May 2016 Encana, REX s largest West-end shipper, agreed to extend its contract (2) Capacity Enhancement Project o o o 0.8 Bcf/d incremental capacity 0.75 Bcf/d contracted with 15-year contracts Expected in-service Q42016 Tallgrass Interstate Gas Transmission TIGT reached a rate case settlement with customers and expects annualized revenue to increase by ~$13 million Pony Express Average volumes for Q2 were ~286k bbl/d 4 th Common Stream o o Tallgrass Terminals Light crude petroleum transportation service from Buckingham to Ponca City and Cushing Light crude petroleum will be batched as a fourth common stream on the pipeline Truck unloading terminal at Buckingham in-service August 2016 Pursuing two additional projects within the existing Tallgrass footprint (1) Based on TEP revolver covenant calculations. (2) REX filed the modified and extended contract with FERC on May 2. 8
Tallgrass Energy Accomplishments TEP IPO TMID Casper Expansion TMID Keep Whole Contract Conversion TIGT West End Expansion TMID Douglas Expansion Revolver Upsize to $850mm Water Business Acquisition Trailblazer Acquisition TMID POP Contract Conversion Commence At-the-Market Equity Program Pony Expansion Open Season ~$330mm TEP follow-on Equity Offering 33.3% Pony Acquisition TEGP IPO ~$570mm TEP follow-on Equity Offering 33.3% Pony Acquisition TEP increases Revolver to $1.1 bn Whiting Water Business Acquisition Pony Expansion Project placed into service $400mm TEP Senior Notes Offering TEP increases Revolver to $1.75bn 31.3% Pony Acquisition 25.0% REX Acquisition 2012 2013 2014 2015 2016 Acquire Assets REX Refinances Notes File REX PDO For Zone 3 East-to-West Transportation Contract REX s Seneca Lateral Contract Trailblazer s Redtail Lateral Pony Northeast Colorado Lateral Open Season REX Receives Favorable PDO Ruling REX Seneca Lateral Expansion Open Season REX E2W Open Season Settle Trailblazer Rate Case REX Signs E2W PAs REX Expansion Open Season REX Settles with 3 MFN Shippers Prairie State Pipeline Open Season with AGL Resources REX Signs Expansion PAs REX Repays $450mm 2015 Notes Seneca Lateral Achieves Full Capacity REX Zone 3 E2W Project placed into service 7(c) FERC application filed for REX Expansion REX Settles with final MFN Shipper REX modifies Encana contract Receives 7(c) approval for REX Expansion Constructs Buckingham Terminal DEVELOPMENT Financing Project Acquisition Other 9
TEP Highlights 10
TEP is a High-Growth Traditional Midstream MLP Crude Oil Transportation and Logistics 764-mile FERC regulated crude oil pipeline from Guernsey, WY / NE Colorado to Cushing, OK ~320,000 bbl/d of transportation design capacity 100% of contractible capacity under firm contracts (1) Low-cost, competitive base load positioning relative to alternatives (e.g., rail) Access to Bakken Shale, DJ, and Powder River production Access to refinery and Cushing, OK oil hub Natural Gas Transportation and Logistics Consists of 3 FERC-regulated natural gas transportation & storage systems (REX, TIGT, and Trailblazer) REX Pipeline (2) 1,712-mile FERC regulated bidirectional natural gas pipeline with up to 1.8 Bcf/d of capacity that transports Rocky Mountain and Appalachian natural gas o Capacity Enhancement Project to increase Zone 3 east-towest capacity to 2.6 Bcf/d TIGT and Trailblazer: ~5,109 miles of pipeline ~2.0 Bcf/d of transportation design capacity ~72% of capacity under firm contract (3) Processing and Logistics Processing and treating ~190 MMcf/d of processing capacity in the Powder River and Wind River s in Wyoming 3,500 bbl/d fractionator at the Casper plant ~60 MMcf/d of CO 2 treating capacity at West Frenchie Draw Water business services Fresh water transportation and salt water gathering and disposal systems in the DJ Effluent management operations in the Eagle Ford Shale and Permian Effluent / fresh water system in Permian and growing Permian disposal opportunities Water recycling services Tallgrass Energy Footprint Tallgrass Interstate Gas Transmission Trailblazer Pipeline Pony Express Pipeline Pony Express Joint Tariff Pipelines Tallgrass Midstream BNN Water Solutions Pipeline Rockies Express Pipeline Lease of Overthrust Pipeline Capacity Oil Storage Terminal (1) 10% of design capacity required to be available for walk-up shippers and is therefore not under contract. (2) TEP owns a 25% membership interest in REX. TDev owns a 50% membership interest and Phillips 66 owns the remaining 25% membership interest in REX. (3) As of 12/31/2015. 11
Highly Stable Cash Flow Profile 95% of TEP s 2015 Adjusted EBITDA was from firm fee / Take or Pay contracts and has been further strengthened by the acquisition of 31.3% of PXP in January 2016 and the acquisition of 25% of REX in May 2016 Crude Oil Transportation & Logistics Segment Processing & Logistics Segment Contract Structure Take or Pay contracts for ~300,000 bbl/d ~92% of TEP s reserved processing capacity subject to fee-based processing contracts Majority of BNN cash flow is Take or Pay based NGL pipeline supported by a 10-year Lease for 100% of its capacity Weighted Average Remaining Life (WARL) (1) ~4 years Processing: ~3 years Freshwater Transportation: ~5 years Water Gathering and Disposal: ~9 years Natural Gas Transportation & Logistics Segment (2) Contract Structure Majority of transportation cash flow is Take or Pay Weighted Average Remaining Life (WARL) (1) TIGT & Trailblazer Transportation: 2 years REX West-to-East Transportation: 5 years REX East-to-West Transportation: 17 years Storage: ~6 years Adjusted EBITDA by Contract Type (3) Volumetric Fee 4% Commodity Exposed 1% Firm Fee 95% (1) As of 12/31/2015. (2) PF for the REX acquisition and REX s Encana contract extension. (3) For the year ended 12/31/2015. 12
Attractive Business Model Stable Operations Crude Oil Transportation & Logistics Segment Firm commitments totaling ~300,000 bbl/d ~4-year WARL (1) Pony provides baseload Rockies takeaway Diversified Supply o Bakken Shale, DJ and Powder River s Diversified Market o Cushing, OK and direct refinery connections Natural Gas Transportation & Logistics Segment Majority of revenue is Take or Pay Attractive future dropdown potential at REX o 17-year WARL on newly contracted 2.5 Bcf/d for REX Zone 3 transportation (1) Access to both Appalachia and Rockies production Strong Financial Profile $1,750mm revolver provides TEP substantial liquidity Raised >$1 billion of capital through public equity issuances since IPO >70% of TEP s PF top 15 customer revenue in 4Q2015 derived from BB+ or better customers Opportunistic ATM equity program Dual public equity currencies and Up-C structure provide increased flexibility 4.0x 3.0x 2.0x Historical Leverage and Coverage Leverage (2) Coverage 1.35x 3.3x 1.30x 2.8x 2.7x 1.25x 1.22x 1.20x 1.7x 1.15x 1.15x 1.14x 1.31x ($ in millions) 1.0x 1.10x Total Debt as of 6/30/16 $1,278 6/30/2016 LTM Adjusted EBITDA (2) 466 Debt / Adjusted EBITDA 2.7x 0.0x 2013 2014 2015 Q2 2016 1.05x 1.00x 2013 2014 2015 1H2016 (1) As of 12/31/15. WARL s based on capacity. (2) Based on TEP revolver covenant calculations. 13
Solid Financial Performance TEP Annualized LP Distribution TEGP Annualized Distribution TEP Guidance Outperformance TEP has consistently met or exceeded guidance At IPO FY2013 FY2014 FY2015 S-1 (1) Adjusted EBITDA Maintenance Capex N/A Coverage DPU $280 $260 $240 $220 $200 $180 $160 $140 $123.12 $97.67 $109.04 $120 $100.00 $100 $80 $60 TEP Total Unit Holder Return Since IPO (2)(3) $187.69 $174.50 $221.28 $220.35 $251.82 $241.93 $213.01 $200.15 $201.71 $246.61 $244.30 Exceeded Guidance Met Guidance NYSE Composite Index (NYATR) Alerian MLP Index (AMZX) Tallgrass Energy Partners, LP (TEP) (1) Represents 12 month period ending 6/30/2014. (2) As of 9/13/2016. (3) Distributions are assumed to be reinvested in units of TEP at the closing price on the ex-dividend date. 14
Appendix 15
Segment and Asset Overview 16
Crude Oil Transportation & Logistics Overview Asset Overview Current Footprint 764-mile FERC regulated crude oil pipeline from Guernsey, WY / NE Colorado to Cushing, OK Total transportation design capacity of ~320,000 bbl/d Take or Pay contracts for a total of ~300,000 bbl/d Powder River Guernsey WY Pawnee NE Pony Pipeline Pony Crude Receipt Pony Pump Station Oil Storage Terminal Refinery s Active Shale Drilling New Supply Connections DJ Diverse Supply Bakken Powder River Additional Common Streams Buckingham Sterling Terminal Niobrara KS CO Mississippi Lime Ponca City Competitive Rates All-in rate to market (gathering, transportation, etc.) is competitive against competing pipelines and rail Batch System Multiple common streams transported in batches preserves value of crude OK Cushing Terminal Operational Update Transported ~290,000 bbl/d for the six months ended June 30, 2016 At least 1 shipper has transported incremental barrels every month since December 2015 Growth Opportunities New Refinery Connections Refinery Cushing Multiple Demand Markets Gulf Coast Additional direct refinery connections Up to an additional ~100,000 bbl/d of capacity can be added with minimal capital expenditure Additional laterals into the DJ 17
Natural Gas Transportation & Logistics Overview Asset Overview Consists of 3 FERC-regulated natural gas transportation & storage systems (REX, TIGT, and Trailblazer) ~6,821 miles of pipelines ~5.6 Bcf/d of transportation design capacity Access to multiple high-growth basins in the Rockies and Appalachia, and multiple large demand centers across the northern US Stable Cash Flow ~95% of PF 2015 segment revenue was Take-or-Pay (1) Volumetric Fee 3% Commodity Exposed 2% Organic Projects REX is adding 0.8 Bcf/d of Zone 3 East-to-West capacity through its Capacity Enhancement Project, expected in-service in December 2016 Trailblazer to construct a lateral for demand customer in 2H 2016 Firm Fee 95% Current Footprint ID Greater Green River Big Horn WY Powder River Niobrara SD HUNTSMAN (Gas storage) NE MN IA WI Michigan MI TIGT Pipeline Trailblazer Pipeline Rex Pipeline Lease Overthrust Capacity TIGT Compressor Station Trailblazer Compressor Station REX Compressor Station s UT Uinta/ Piceance Paradox Niobrara CO KS Mississippi Lime Cherokee Platform Forest City MO IL Illinois IN KY Active Shale Drilling OH Appalachian WV (1) PF 2015 segment revenue includes 25% of 2015 REX revenue for purposes of this calculation. 18
Rockies Express Pipeline Overview Prominent pipeline providing natural gas transportation service to North American energy markets REX is becoming the nation s northernmost natural gas header system Attractive access to both supply basins and large end user markets Currently moving both Rocky Mountain and Appalachian production Opal Wamsutter Shale to Shining Shale Zone 1 Zone 2 Zone 3 Kanda Meeker Cheyenne Clarington ROCKIES EXPRESS PIPELINE SENECA LATERAL LEASE OF OVERTHRUST CAPACITY REX COMPRESSOR STATION Lebanon Asset Overview Highlights Placed in service in November 2009 ~1,712 miles of 42 and 36 pipeline ~1.8 Bcf/d of West-to-East capacity ~2.6 Bcf/d of Zone 3 East-to West-capacity (1) Contracted capacity supports stable cash flow Access to substantially all major natural gas supply basins in the Rocky Mountain region, Ohio and Pennsylvania corridors Favorable proximity to numerous major enduse markets Encana s contract Extended through 2024 ~0.5 Bcf/d of west-end volume contracted through 2024 Zone 3 for bidirectional flows ~2.5 Bcf/d contracted of 2.6 Bcf/d Zone 3 East-to-West capacity First East-to-West volumes flowed in June 2014 Majority of contracts are 15-20 year terms REX repaid $450 million of bond maturities in 2015 >75% of the 2019 recontracting risk has been mitigated, as it relates to FY2013 Revenue 98% of 2015 revenue was Take or Pay Weighted Average Contract Life (2) East-to-West Contracts: ~17 years West-to-East Contracts: ~5 years Partners will fund ~$750 million of capital projects from 2014-2017 with 100% equity and no debt Note: Overthrust Pipeline is owned by Questar and consists of ~255 miles of pipeline. (1) Pro forma for Capacity Enhancement project in-service. (2) Calculation date of 12/31/2015. 19
Recontracting REX Securing Long-Term Revenue Revenue as of 2013 Revenue as of 2015 Revenue as of Today Original Contracts Only Contracted revenue expired late 2019, future revenue was unknown ($ in millions) Historic Forecast $1,000 $750 $500 $250 $750 $500 $250 Encana Extension Securing an extended Encana contract levelizes REX s contracted revenue, and significantly reduces future recontracting risk ($ in millions) >75% of the 2019 cash flow risk has $1,000 Historic Forecast been mitigated with current contracts $750 $500 $250 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Encana Other West End Contracts 2013 Revenue East-End Secured Addition of East-end contracts extended the contracted revenue ($ in millions) Historic Forecast $1,000 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 East End Encana Other West End Contracts 2013 Revenue 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 (1) East End Encana Other West End Contracts 2013 Revenue (1) (1) Forecast assumes no Ultra or LINN revenues. 20
Processing & Logistics Overview Asset Overview Processing Footprint Processing and treating ~190 MMcf/d of processing capacity in the Powder River (PRB) and Wind River basins in Wyoming 3,500 bbl/d fractionator at the Casper plant ~60 MMcf/d of CO2 treating at West Frenchie Draw Water business services Fresh water transportation and salt water gathering and disposal system in the DJ Effluent management operations in the Eagle Ford Shale and Permian NGL Pipeline Provides NGL takeaway from the Redtail processing plant in Weld County, Colorado to an interconnect with Overland Pass Pipeline Supported by a ten year lease for 100% of the pipeline capacity Big Horn Greater Green River Uinta/ Piceance Powder River Niobrara Niobrara WY TIGT Pipeline s Active Shale Drilling CO NE West Frenchie Draw Douglas Casper Processing and Logistics Growth Opportunities Processing and Treating Contract Mix (1) Processing and treating Additional processing capacity in the PRB is permitted Discussing the construction of gathering lines to service multiple customers in the PRB Water business services Additional water management services to meet the full spectrum of producers needs (fresh water, recycling, waste water disposal) To construct NGL takeaway pipeline from Douglas to ONEOK s Bakken Express pipeline in 2H 2016 (1) As of 12/31/2015. Percentages based on contracted capacity. POP / KW 8% Fee-Based 92% 21
Drop Down Opportunity: Tallgrass Terminals (1) Tallgrass Energy is utilizing the Pony system as an entry point into the terminals business WY Powder River Guernsey NE Located at the intersection of the Guernsey to Sterling and NECL line segments of Pony Provides over 1 million bbls of operational storage for Pony Pawnee Buckingham Sterling Terminal Pursuing growth opportunities to expand business into nearby areas and operations Niobrara KS Tallgrass Development acquired a 20% interest in the Deeprock Development Cushing Terminal (2) Storage capacity of ~2.3 million bbls CO Mississippi Lime Offers pump over services to numerous terminals and pipeline takeaway options OK Ponca City Provides Tallgrass Energy a presence in the nation s largest oil hub to source new projects Pony Pipeline Pony Crude Receipt Pony Pump Station Oil Storage Terminal Refinery Cushing Terminal s Active Shale Drilling Other Acquired 550 acres in Cushing, OK and commercializing additional storage in Cushing Constructed Buckingham terminal at a NECL receipt point Kansas terminal opportunities (1) Tallgrass Terminals is not a Tallgrass Development Retained Asset under the Omnibus Agreement between TEP and TDEV and is not a part of Pony. (2) Tallgrass Terminals owns 20% of a joint venture, which owns and operates an oil terminal facility in Cushing, OK. 22
EBITDA and DCF Reconciliations 23
TEP Revolver Covenant Compliance EBITDA Reconciliation For the Four Quarters Ended June 30, 2016 LTM ($ in millions) 6/30/16 Consolidated Net Income (1) 349.8 + Consolidated Interest Expense (Excluding AFUDC to avoid double counting) 24.9 + Depreciation & Amortization, Net of NCI 86.8 + Expenses related to equity-related benefit plans 4.5 Total Consolidated EBITDA 465.9 (1) Consolidated Net Income shall mean, as of any Date of Determination for the Applicable Period related thereto, the net income (or loss) of the Borrower and its Restricted Subsidiaries on a consolidated basis in accordance with GAAP; provided, however, that Consolidated Net Income shall exclude (a) extraordinary gains, losses, charges or expenses for such Applicable Period, (b) the net income of any Restricted Subsidiary during such Applicable Period to the extent that the declaration or payment of dividends or similar distributions by such Restricted Subsidiary of such income is not permitted on such Date of Determination by operation of the terms of its Organizational Documents or any agreement, instrument or law applicable to such Restricted Subsidiary, except that the Borrower s equity in any net loss of any such Restricted Subsidiary for such Applicable Period shall be included in determining Consolidated Net Income, (c) any income (or loss) for such Applicable Period of any Person if such Person is not a Restricted Subsidiary of the Borrower, except that the aggregate amount of cash actually distributed by such Person during such Applicable Period to the Borrower or a Restricted Subsidiary of the Borrower as a dividend or other distribution (as long as, in the case of a dividend or other distribution to a Restricted Subsidiary of the Borrower, such Restricted Subsidiary is not precluded from further distributing such amount to the Borrower as described in clause (b) of this proviso) shall be included in Consolidated Net Income, (d) non-cash gains and losses attributable to movement in the mark-to-market valuation of Hedging Agreements pursuant to Financial Standards Accounting Board ( FASB ) Accounting Standards Codification ( ASC 815 ), (e) the cumulative effect of a change in accounting principles, (f) any charges or expenses relating to severance, relocation and one-time compensation charges, (g) gain or loss realized upon the sale or other disposition of assets, (h) deferred financing costs written off and premiums paid in connection with any early extinguishment of Indebtedness or any Hedging Agreement, (i) non-cash charges, expenses or other impacts of purchase or recapitalization accounting, including, to the extent applicable, any accruals and reserves established under purchase or recapitalization accounting as a result of the Transactions in accordance with GAAP, (j) non-cash impairment charges or asset write-offs, and any amortization of intangibles, (k) cash charges or costs in connection with any investment, sale or other disposition of assets, issuance of Equity Interests or Indebtedness, or amendment relating to any Indebtedness (in each case, whether or not completed), and (l) to the extent covered by insurance and actually reimbursed, any expenses with respect to liability or casualty events or business interruption. 24
TEP Adjusted EBITDA & DCF Reconciliation Three Months Ended June 30, Years Ended December 31, (in millions) 2016 2015 2014 2013 (1) Net income attributable to partners $ 92.0 $ 160.5 $ 70.7 $ 9.7 Add: Interest expense, net of noncontrolling interest 9.2 15.5 7.6 11.0 Depreciation and amortization expense, net of noncontrolling interest 21.8 75.5 45.4 37.9 Loss on extinguishment of debt 0.2 17.5 Non-cash (gain) loss related to derivative instruments (18.8) (0.2) 0.4 Non-cash compensation expense 1.5 5.1 5.1 1.8 Non-cash loss from disposal of assets 1.8 4.8 Distributions from unconsolidated investment 29.7 1.5 Less: Non-cash loss allocated to noncontrolling interest (9.4) (10.2) Gain on remeasurement of unconsolidated investment (9.4) Equity in earnings of unconsolidated investment (23.3) (0.7) Adjusted EBITDA $ 114.0 $ 252.3 $ 109.9 $ 78.4 Add: Pony Express preferred distributions in excess of distributable cash flow attributable to Pony Express 5.4 Pony Express deficiency payments received, net 8.6 16.5 5.4 Less: Cash interest cost (8.4) (13.7) (6.3) (5.9) (2) Maintenance capital expenditures (2.1) (12.1) (9.9) (16.0) Distributions to noncontrolling interest in excess of earnings (22.5) (5.4) Cash flow attributable to predecessor operations (3.1) 3.4 Distributable Cash Flow 112.1 220.5 96.1 59.9 (2) Less: Distributions (79.6) (192.6) (83.3) (49.1) (2) Amounts in excess of distributions (2) $ 32.5 $ 27.9 c $ 12.7 $ 10.8 Distribution coverage 1.41 1.14 1.15 1.22 (2) (1) The financial results for the year ended December 31, 2013 have been recast to reflect the results of operations of Trailblazer Pipeline Company LLC, which TEP acquired effective April 1, 2014, and the 33.3% membership interest in Tallgrass Pony Express Pipeline, LLC, which TEP acquired effective September 1, 2014. (2) Indicated amounts presented for the year ended December 31, 2013 are on a pro forma basis, which assumes that our initial public offering and related formation transactions, including borrowings under our revolving credit facility, had closed on January 1, 2013. No cash distributions were paid with respect to the first quarter of 2013, and a prorated distribution of available cash was paid for the period from the closing of the IPO (May 17, 2013) through the end of the second quarter. Pro forma distributions were calculated using the minimum quarterly distribution for the first two quarters of 2013 and the increased distribution for the third and fourth quarters. Actual cash distributions for the twelve month period ending December 31, 2013,were $0.7547/unit. Pro forma interest expense (inclusive of commitment fees) for the twelve months ended December 31, 2013, was calculated by multiplying the actual cash interest cost for the third quarter by three and adding the actual cash interest cost for the fourth quarter. Actual cash interest cost for the twelve month period ended December 31, 2013, was $3,555,000. 25