Table of Contents Standardized Measure of Discounted Future Net Cash Flows 131 Following is an analysis of changes in the standardized measure during 2018, 2017 and 2016: Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the year-end statutory rate to the excess of pre-tax cash inflows over the Company’s tax basis in the associated proved gas and oil properties after giving effect to permanent differences and tax credits. Under the standardized measure, future cash inflows were estimated by applying an average price from the first day of each month from the previous 12 months, adjusted for known contractual changes, to the estimated future production of year-end proved reserves. Prices used for the standardized measure above were as follows: (1) Includes abandonment costs. (2) The December 31, 2016 standardized measure computation does not have future income taxes because the Company’s tax basis in the associated oil and gas properties exceeded expected pre-tax cash inflows. Future net cash flows are not permitted to be increased by excess tax basis. The following standardized measures of discounted future net cash flows relating to proved natural gas, oil and NGL reserves as of December 31, 2018, 2017 and 2016 are calculated after income taxes, discounted using a 10% annual discount rate and do not purport to present the fair market value of the Company’s proved gas, oil and NGL reserves: The Company has no reserves from synthetic gas, synthetic oil or nonrenewable natural resources intended to be upgraded into synthetic gas or oil. The Company used standard engineering and geoscience methods, or a combination of methodologies in determining estimates of material properties, including performance and test date analysis, offset statistical analogy of performance data, volumetric evaluation, including analysis of petrophysical parameters (including porosity, net pay, fluid saturations (i.e., water, oil and gas) and permeability) in combination with estimated reservoir parameters (including reservoir temperature and pressure, formation depth and formation volume factors), geological analysis, including structure and isopach maps and seismic analysis, including review of 2-D and 3-D data to ascertain faults, closure and other factors. (in millions) 2018 2017 2016 Future cash inflows $ 34,523  $ 36,576  $ 9,064  Future production costs (15,347) (18,390) (5,880) Future development costs  (1) (4,095) (4,676) (485) Future income tax expense  (2) (2,079) (1,342) – Future net cash flows 13,002  12,168  2,699  10% annual discount for estimated timing of cash flows (7,003) (6,606) (1,034) Standardized measure of discounted future net cash flows $ 5,999  $ 5,562  $ 1,665  (in millions) 2018 2017 2016 Natural gas  (per MMBtu) $ 3.10  $ 2.98  $ 2.48  Oil  (per Bbl) 65.56  47.79  39.25  NGLs  (per Bbl) 17.64  14.41  6.74  (in millions) 2018 2017 2016 Standardized measure, beginning of year $ 5,562  $ 1,665  $ 2,417  Sales and transfers of natural gas and oil produced, net of production costs (1,564) (1,191) (574) Net changes in prices and production costs 2,162  1,963  (415) Extensions, discoveries, and other additions, net of future production and development costs 335  1,715  45  Acquisition of reserves in place – – – Sales of reserves in place (2,022) – (10) Revisions of previous quantity estimates 361  1,721  (140) Net change in income taxes (304) (222) – Changes in estimated future development costs (166) (6) 71  Previously estimated development costs incurred during the year 536  55  114  Changes in production rates (timing) and other 521  (304) (85) Accretion of discount 578  166  242  Standardized measure, end of year $ 5,999  $ 5,562  $ 1,665  Index to Financial Statements