Estimated Costs Related to Conversion of Proved Undeveloped Reserves to Proved Developed Reserves Preparation of Reserve Estimates The following table sets forth the estimated timing and cash flows of developing our proved undeveloped reserves at December 31, 2018 ( $ in thousands ): (2) Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (BOE). (3) Computation is based on SEC pricing of (i) $61.18 per Bbl (WTI-Cushing spot prices, adjusted for differentials) and (ii) $2.13 per Mcf (Henry Hub spot natural gas price), as adjusted for location and quality by property. Historically, our drilling programs have been substantially funded from our cash flow and borrowings under our credit facility. Based on current commodity prices and our current expectations over the next five years of our cash flows and drilling programs, which includes drilling of proved undeveloped and unproven locations, we believe that we can continue to substantially fund our drilling activities from our cash flow and with borrowings under the EEH Credit Agreement. In addition, historically, we have been able to take advantage of the capital markets, as needed, when opportunities arose. We engaged an independent petroleum engineering consulting firm, CG&A, to prepare our annual reserve estimates and we have relied on CG&A’s expertise to ensure that our reserve estimates are prepared in compliance with SEC guidelines. The technical person primarily responsible for the preparation of the reserve report is Mr. W. Todd Brooker, President of CG&A. He graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering. Mr. Brooker is a Registered Professional Engineer in the State of Texas (License No. 83462) and has more than 25 years of experience in the estimation and evaluation of oil and natural gas reserves. He is also a member of the Society of Petroleum Engineers. Robert J. Anderson, our President, is responsible for reservoir engineering, is a qualified reserve estimator and auditor and is primarily responsible for overseeing CG&A during the preparation of our annual reserve estimates. His professional qualifications meet or exceed the qualifications of reserve estimators and auditors set forth in the “Standards Pertaining to Estimation and Auditing of Oil and Natural Gas Reserves Information” promulgated by the Society of Petroleum Engineers. His qualifications include a Bachelor of Science degree in Petroleum Engineering from the University of Wyoming in 1986; a Master of Business Administration degree from the University of Denver in 1988; member of the Society of Petroleum Engineers since 1985; and more than 32 years of practical experience in estimating and evaluating reserve information with more than fifteen of those years being in charge of estimating and evaluating reserves. We maintain adequate and effective internal controls over our reserve estimation process as well as the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are technical information, financial data, ownership interest and production data. The relevant field and reservoir technical information, which is updated, at least, annually, is assessed for validity when CG&A has technical meetings with our engineers, geologists, operations and land personnel. Current revenue and expense information is obtained from our accounting records, which are subject to external quarterly reviews, annual audits and our own set of internal controls over financial reporting. Internal controls over financial reporting are assessed for effectiveness annually using criteria set forth in  Internal Control – Integrated Framework , (2013 Version) issued by the Committee of Sponsoring Organizations of the Treadway Commission. All current financial data such as commodity prices, lease operating expenses, Years Ended December 31, (1) Future Production (MBOE) (2) Future Cash Inflows (3) Future Production Costs Future Development Costs Future Net Cash Flows 2019 1,062 $ 56,535 $ 6,043 $ 124,864 $ (74,372 ) 2020 3,459 174,328 20,372 251,365 (97,409) 2021 6,585 320,411 38,097 287,984 (5,671 ) 2022 8,794 416,045 50,573 298,916 66,556 2023 7,457 331,444 42,643 — 288,802 Thereafter 47,844 2,082,720 521,417 — 1,561,303 Total 75,201 $ 3,381,483 $ 679,145 $ 963,129 $ 1,739,209 (1) Beginning in 2019 and thereafter, the production and cash flows represent the drilling results from the respective year plus the incremental effects from the results of proved undeveloped drilling from previous years. These production volumes, inflows, expenses, development costs and cash flows are limited to the PUD reserves and do not include any production or cash flows from the Proved Developed category which will also help to fund our capital program. 42