Investor Presentation August 2016
Disclaimer Forward-Looking Statements This presentation includes forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as may, assume, forecast, position, predict, strategy, expect, intend, plan, estimate, anticipate, believe, project, budget, potential, or continue, and similar expressions are used to identify forwardlooking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. You are cautioned not to place undue reliance on any forward-looking statements. We caution you that these forward-looking statements are subject to all of the risks and uncertainties incident to our business, most of which are difficult to predict and many of which are beyond our control. We disclose important factors that could cause our actual results to differ materially from our expectations in the Risk Factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2015 and filed with the Securities and Exchange Commission on February 26, 2016. These risks include, but are not limited to, the inability of our primary customer to execute its drilling and development plan; our ability to successfully implement our business strategy; fluctuations in commodity prices, including realized natural gas, NGLs and oil prices; actions taken by third-party producers, operators, processors and transporters; general economic conditions; credit markets; regulatory changes; the uncertainty inherent in projecting future rates of production, cash flow and access to capital; and others. Should one or more of the risks or uncertainties associated with our midstream business occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements herein, to reflect events or circumstances after the date of this presentation. Non-GAAP Financial Measures In this presentation, we present Adjusted EBITDA and distributable cash flow, which are non-gaap financial measures. Adjusted EBITDA and distributable cash flow are used as supplemental financial measures by our management and external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess: the ability of our business to generate sufficient cash flow to support our decision to make distributions to our unitholders; our ability to incur and service debt and fund capital expenditures; our financial performance as compared to other publicly traded companies in our industry, without regard to historical cost basis or financing methods and the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities. We believe that the presentation of Adjusted EBITDA and distributable cash flow provide information useful to investors in assessing our financial condition and results of operations. We define Adjusted EBITDA as net income, plus interest expense, income taxes, depreciation and amortization, changes in deferred revenue, equity-based compensation expense, non-cash general and administrative expenses, non-cash loss (income) related to derivative instruments and impairments on long-term assets. We define distributable cash flow as Adjusted EBITDA, less cash interest expense related to operating activities, net of interest income, income taxes paid, maintenance capital expenditures and distribution equivalents paid in cash. We have included a reconciliation of Adjusted EBITDA to net operating cash flow from operating activities, at the end of this presentation. Adjusted EBITDA and distributable cash flow should not be considered as alternatives to the GAAP measures of net income, operating income or cash flows from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and distributable cash flow are not presentations made in accordance with GAAP and have important limitations as analytical tools because they include some, but not all, items that affect net income and net cash provided by operating activities, as applicable, and these measures may vary among other companies. As a result, Adjusted EBITDA and distributable cash flow as presented herein may not be comparable to similarly titled measures of other companies. You should not consider Adjusted EBITDA or distributable cash flow in isolation or as substitutes for analysis of results as reported under GAAP. 2
PTXP Update: Operations and Events Declared a quarterly distribution of $0.2846 / unit for Q2 2016 3.5% increase over prior quarter Increased net income, Adjusted EBITDA (1) and distributable cash flow (1) from the first quarter Increased 2016 guidance for distributable cash flow (2) to $60 - $63 million from $56 - $59 million Averaged 266,000 MMBtu/d in processing volumes for the three months ended June 30, 2016 Primary customer, Memorial Resource Development Corp. (NASDAQ: MRD), announced a definitive merger agreement with Range Resources Corporation (NYSE: RRC); the transaction is expected to close in late Q3 2016 Minimum volume commitments under the Partnership s gathering and processing agreements with MRD increased to 460,000 MMBtu/d effective July 1, 2016 Evaluating additional infrastructure build-out for MRD expansion acreage 1) See reconciliation on page 12 2) See page 5 for a discussion of the unavailability of a comparable GAAP measure on a forward-looking basis 3
PTXP Update: Q2 2016 Financial Overview Financial Summary Capitalization Q2 Financial Results Net income of $4.2 million Operating cash flow of $14.9 million Adjusted EBITDA (1) of $15.5 million Distributable cash flow ( DCF ) (1) of $14.0 million Leverage ratio of 2.7x at the end of the quarter Distributions Quarterly distribution of $0.2846 / unit for Q2 2016 ($ and units in millions) Common units 20.2 Subordinated units 20.0 Total units outstanding 40.2 Unit price as of 7/29/2016 $16.38 Market c apitalization $658.2 Plus: Credit facility borrowings and LOCs 158.0 Less: Cash on hand (1.7) Enterprise value $814.5 Operating Results ($ in millions, except per unit amounts) Three Months Ended June 30, 2016 Operating c ash flow $14.9 Adjusted EBITDA (1) $15.5 Distributable cash flow (1) $14.0 Distribution dec lared $11.4 Distribution / unit $0.2846 Liquidity as of June 30, 2016 ($ in millions) Revolving credit facility (total size) $275.0 Less: amount drawn (157.0) Less: letters of credit outstanding (1.0) Availability under revolving c redit fac ility $117.0 Plus: cash on hand 1.7 Liquidity $118.7 Distribution c overage ratio (dec lared basis) 1.22x 1) See reconciliation on page 12 4
Increasing 2016 Guidance Full-year 2016 DCF guidance increased from $56-$59 million to $60 - $63 million ($MM) $75 $36 $63 $60 $33 $60 $45 1H 2016 Actual: $27.3 MM $30 $27 $14.0 $15 $13.3 $0 Q1 2016 Actual Q2 2016 Actual 2H 2016 Estimate FY 2016 Guidance Range Note: Distributable cash flow is a non-gaap measure and, on a forward-looking basis, a comparable GAAP measure is unavailable because the Partnership is unable to predict with reasonable certainty and without unreasonable effort, items such as changes in working capital, impairments, depreciation and amortization and non-cash general and administrative expenses. These items are uncertain, depend on various factors and could be material to the Partnership s results computed in accordance with GAAP. 5
PTXP Investment Highlights Attractive Distribution Growth Financial Flexibility Predictable Cash Flow Profile Strong Minimum Volume Commitments Premier Basin Strategically Located Assets 6
Strategic Market Location ( $ ) Discount to Henry Hub 1 Proximity to LNG Export Facilities 5 out of 6 FERC approved, under construction LNG exports facilities are on the Gulf Coast PG&E Malin + ($0.07) NGPL Midcontinent ($0.11) Perryville Hub ($0.08) ($1.50) Dominion South Point 2 3 Proximity to Expanding Industrial Demand Expanding industrial demand centered on the Gulf Coast petrochemical sector + Low Differentials Waha ($0.10) ($0.07) Henry Hub North Louisiana (Perryville Hub) differential of ($0.08)/Mcf compared to: Dominion South Point ($1.50)/Mcf NGPL Midcontinent ($0.11)/Mcf Houston Ship Channel Waha ($0.10)/Mcf Houston Ship Channel ($0.07)/Mcf PG&E Malin ($0.07)/Mcf Sources: MRD IPAA OGIS investor presentation dated 4/11/2016; RRC Q2 results investor presentation dated 7/26/2016; FERC, as of 7/11/2016; Bloomberg spot basis differentials as of 7/29/2016 7
Top Underlying Acreage PTXP s gathering, transport and processing assets support a very high quality upstream asset Low-Risk Development Relatively low-risk horizontal redevelopment of legacy vertical fields Significant existing geologic and 3-D seismic data Well studied structure allows for repeatable results Top-Tier Well Results and Impressive Well Economics High IP(30)s: 101 of MRD s 105 horizontal wells have been in the top 10% of horizontal wells completed since 2012 (1) Compelling returns: >100% IRRs on Upper Red wells, based on MRD estimates at current well costs (2) ~50% IRRs on Lower Red wells, based on MRD estimates at current well costs (2) ~30% IRRs on Deep Pink wells, based on MRD estimates at current well costs (2) Terryville Upper Red wells breakeven at $1.45/MMBtu (PV-10 basis) one of, if not the lowest, gas play breakevens (3) Ample Inventory Stacked pay resource: 4 over pressured Lower Cotton Valley zones + 9 normally pressured Upper Cotton Valley zones (4) 100+ year inventory under MRD s current drilling program (5) Range Resources also cites five potential extension areas similar to the Terryville and Vernon fields (6) 1) Source: MRD IPAA OGIS investor presentation dated 4/11/2016, p. 8. Note: Based on peak 30 day equivalent production. MRD data shown includes NGLs after processing; all other well results based on data as reported per HPDI. MRD data uses estimated shrink and NGL yields for recent horizontal wells. Well percentile based on peak 30-day Mcfe production for over 20,800 horizontal gas wells in the U.S. drilled since 2012 2) Source: MRD IPAA OGIS investor presentation dated 4/11/2016, p. 7. Note: Based on MRD internal type curve estimates. Assumes NYMEX Strip as of 12/31/2015, 7,500 foot lateral length, 100% WI/ 78% NRI and operating costs within MRD s full year 2016 guidance range assumptions as of 2/2/2016 3) Source: U.S. Capital Advisors MRD Initiation Report, 12/28/2015, p. 18. Note: based on BTAX breakeven economics. Assumes a $0.75/MMBtu L-T basis/transport cost for the Appalachian Basin 4) Source: MRD IPAA OGIS investor presentation dated 4/11/2016, p. 24 5) Source: MRD IPAA OGIS investor presentation dated 4/11/2016, p. 7. Years of inventory calculated as MRD management locations divided by midpoint of 2016 guidance for wells completed (32.5 wells) 6) Source: RRC Q2 results investor presentation dated 7/26/2016, p. 21 8
Range Resources / MRD Announcement On May 16 th, Memorial Resource Development Corp. (NASDAQ: MRD) announced a merger agreement with Range Resources Corporation (NYSE: RRC) The transaction requires MRD and RRC stockholder approvals, for which the special meetings and stockholder votes are scheduled for September 15, 2016 Closing expected late Q3 2016 Jeffrey Ventura (Chairman, President & CEO of Range Resources Corp.) on the transaction (1) : An accretive transaction that competes with our peer-leading results in the Southwest Marcellus is not a small hurdle, therefore any potential transaction has to start with high quality assets. The Terryville assets, particularly the Upper Red, are highly prolific wells developed by a high quality technical team, as evidenced by their industry-leading production rates per well. Similar to the Marcellus, the Upper Red is a relatively low-risk, repeatable, high-quality rock. 1) Source: Event transcript for RRC call announcing the merger with MRD on 5/16/2016 9
PTXP Contract Strength = Low-Risk DCF Growth ($MM) $75 Future cash receipts assuming no volume throughput, 100% MVC, firm and demand charge revenue (1) $74.4 $60 Increase in firm billings of $3.9MM per quarter ($7.8MM for 2H 2016) $20.5 $45 $20.5 $30 $16.7 $15 $16.7 $0 Q1 2016 Q2 2016 Q3 2016 Q4 2016 FY 2016 On July 1, 2016, MRD s gathering and processing minimum volume commitments increased from 345,000 MMBtu/d to 460,000 MMBtu/d Firm billings to increase in 2H 2016 by $3.9MM per quarter ($7.8MM for 2H 2016) MVC step-up provides visible and low-risk DCF growth in 2H 2016 Note: values may not sum due to rounding 1) Values reflect total billed (including revenue and deferred revenue) assuming no physical volumes are delivered by MRD. For illustrative purposes, assumes gathering MVC deficiency payments are settled quarterly (vs. year-end). Includes 460,000 MMBtu/d of gathering demand charge volume and $360,000/month for priority firm gas transportation service for the first 100,000 MMBtu per day of residue gas delivered by MRD 10
Appendix 11
Reconciliation of Non-GAAP Measures Reconciliation of Net Operating Cash Flow to Distributable Cash Flow: Net cash provided by operating activities $14,902 Plus: Cash interest expense related to operating activities 1,286 Changes in working capital (656) Adjusted EBITDA $15,532 Less: Cash interest expense related to operating activities 1,286 M aintenance capital expenditures 32 Distribution equivalents payable in cash 227 Distributable Cash Flow $13,987 Calculation of Adjusted EBITDA: Net income $4,168 Add: expense, net 1,620 Depreciation and amortization expense 3,381 Changes in deferred revenue 3,912 Equity-based compensation expense 1,210 Non-cash contribution for general and administrative expense 1,241 Adjusted EBITDA $15,532 Note: Adjusted EBITDA and distributable cash flow are supplemental non-gaap financial measures that are used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net income, plus interest expense, income taxes, depreciation and amortization, changes in deferred revenue, equity-based compensation expense, non-cash general and administrative expenses, non-cash loss (income) related to derivative instruments and impairments on long-term assets. We define distributable cash flow as Adjusted EBITDA, less cash interest expense related to operating activities, net of interest income, income taxes paid, maintenance capital expenditures and distribution equivalents paid in cash. Adjusted EBITDA and distributable cash flow should not be considered as alternatives to the GAAP measures of net income, operating income or cash flows from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and distributable cash flow are not presentations made in accordance with GAAP and have important limitations as analytical tools because they include some, but not all, items that affect net income and net cash provided by operating activities and these measures may vary among other companies. As a result, Adjusted EBITDA and distributable cash flow as presented herein may not be comparable to similarly titled measures of other companies. You should not consider Adjusted EBITDA or distributable cash flow in isolation or as substitutes for analysis of results as reported under GAAP. 12
PTXP Overview 13
Organizational Structure PennTex Midstream Partners, LLC MRD WHR LA (1) 92.5% Membership 7.5% Membership 100% Membership 26.2% LP (1) 7.5% IDR PennTex Midstream GP, LLC Non-economic General Partner Public Unitholders 34.5% LP 39.2% LP 92.5% IDR PennTex Midstream Management Company, LLC PennTex Midstream Partners, LP (NASDAQ: PTXP) 100% Membership $275MM Credit Facility Services and Secondment Agreement Operating Subsidiaries 1) Represents units and interests issued or conveyed to MRD WHR LA Midstream LLC at IPO (giving effect to partial exercise of underwriters overallotment option), which was subsequently distributed to members 14
Asset Overview Asset Summary North Louisiana Area of Exclusivity with MRD Processing Assets 400 MMcf/d of processing capacity: Lincoln Parish plant: 200 MMcf/d cryogenic nameplate capacity, completed May 2015 Mt. Olive plant: 200 MMcf/d cryogenic nameplate capacity, completed October 2015 Other Infrastructure 36 miles of rich natural gas gathering pipeline 15 miles of residue natural gas pipeline 40 mile NGL pipeline Lincoln Parish Plant PennTex Gathering Pipeline PennTex Residue Gas Pipeline PennTex NGL Pipeline Mt. Olive Plant 15
Operational Milestones Corporate Events PennTex History Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 PennTex was founded by NGP and management in January 2014 Formed PennTex North Louisiana joint venture and signed exclusivity agreement with predecessor to MRD PTXP closes $225MM IPO of North Louisiana platform Began constructing Plant I (200 MMcf/d cryogenic processing plant) MRD exercises option for PennTex construction of Plant II (200 MMcf/d cryogenic processing plant) PennTex begins construction on Plant II PennTex places Plant I into service PennTex places Plant II into service 16