EXHIBIT 99.4
BELLATRIX EXPLORATION LTD.
SUPPLEMENTARY OIL AND GAS INFORMATION - (UNAUDITED)
The following disclosures have been prepared by Bellatrix Exploration Ltd. (“Bellatrix”) in accordance with Accounting Standards Codification 932 “Extractive Activities — Oil and Gas” (“ASC 932”) issued by the Financial Accounting Standards Board. Bellatrix prepares its consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”), and prepares and files its reserves information under National Instrument 51-101 —Standards of Disclosure of Oil and Gas Activities (“NI 51-101”) which prescribes the standards for the preparation and disclosure of reserves and related information for companies subject to continuous disclosure obligations in Canada. There are significant differences between reserves disclosure under NI 51-101 and the requirements of the United States Securities and Exchange Commission (the “SEC”), including the type of volumes disclosed and the basis from which the volumes are economically determined under the United States Securities and Exchange Commission (“SEC”) requirements and NI 51-101. The SEC requires disclosure of net reserves, after royalties, using 12-month average prices and current costs; whereas NI 51-101 requires gross reserves, before royalties, using forecast pricing and costs. For the purposes of determining proved crude oil and natural gas reserves for SEC requirements as at December 31, 2016 and 2015, Bellatrix used the 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. Therefore the difference between the reported numbers under the two disclosure standards can be material.
NET PROVED OIL AND NATURAL GAS RESERVES
Bellatrix engaged an independent qualified reserve evaluator, InSite Petroleum Consultants Ltd. (“InSite”), to evaluate Bellatrix’s proved developed and proved undeveloped oil and natural gas reserves. As at December 31, 2016, all of Bellatrix’s oil and natural gas reserves are located in Canada. The changes in our net proved reserve quantities are outlined below.
Net reserves include Bellatrix’s remaining working interest and royalty reserves, less all Crown, freehold, and overriding royalties and other interests that are not owned by Bellatrix.
Proved reserves are those estimated quantities of crude oil, natural gas and natural gas liquids that can be estimated with a high degree of certainty to be economically recoverable under existing economic and operating conditions.
Proved developed reserves are those proved reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure to put the reserves on production. Proved developed reserves may be subdivided into producing and non-producing.
Proved undeveloped reserves are those reserves that are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production.
Bellatrix cautions users of this information as the process of estimating crude oil and natural gas reserves is subject to a level of uncertainty. The reserves are based on economic and operating conditions; therefore, changes can be made to future assessments as a result of a number of factors, which can include new technology, changing economic conditions and development activity.
YEAR ENDED DECEMBER 31, 2016
CONSTANT PRICES AND COSTS
Net Proved Developed and
Proved Undeveloped Reserves (1) | | Crude Oil
(mbbl) | | | Natural Gas
Liquids
(mbbl) | | | Natural
Gas
(mmcf) | | | Oil
Equivalent
(mboe) | |
| December 31, 2015 | | | 6,444.9 | | | | 17,272.8 | | | | 323,845 | | | | 77,691.9 | |
| Revisions of previous estimates | | | (1,897.5 | ) | | | 1,559.9 | | | | 62,259 | | | | 10,038.8 | |
| Improved recovery | | | — | | | | — | | | | — | | | | — | |
| Purchases of minerals in place | | | — | | | | 1,371.0 | | | | 30,029 | | | | 6,375.8 | |
| Extensions and Discoveries | | | 19.0 | | | | 3,440.0 | | | | 66,415 | | | | 14,528.2 | |
| Production | | | (652.0 | ) | | | (2,174.0 | ) | | | (56,892 | ) | | | (12,307.9 | ) |
| Sales of minerals in place | | | (2,931.0 | ) | | | (1,991.9 | ) | | | (23,842 | ) | | | (8,896.6 | ) |
| December 31, 2016 | | | 983.4 | | | | 19,477.8 | | | | 401,814 | | | | 87,430.2 | |
| | | | | | | | | | | | | | | | | |
| Proved Developed Reserves | | | | | | | | | | | | | | | | |
| Beginning of year | | | 3,865.7 | | | | 8,926.3 | | | | 168,903 | | | | 40,942.5 | |
| End of year | | | 943.6 | | | | 8,631.7 | | | | 196,841 | | | | 42,382.1 | |
| Proved Undeveloped Reserves | | | | | | | | | | | | | | | | |
| Beginning of year | | | 2,579.2 | | | | 8,346.5 | | | | 154,942 | | | | 36,749.4 | |
| End of year | | | 39.8 | | | | 10,846.2 | | | | 204,973 | | | | 45,048.1 | |
| Total(2) | | | 983.4 | | | | 19,477.8 | | | | 401,814 | | | | 87,430.2 | |
YEAR ENDED DECEMBER 31, 2015
CONSTANT PRICES AND COSTS
Net Proved Developed and
Proved Undeveloped Reserves (1) | | Crude Oil
(mbbl) | | | Natural Gas
Liquids
(mbbl) | | | Natural
Gas
(mmcf) | | | Oil
Equivalent
(mboe) | |
| December 31, 2014 | | | 14,940.3 | | | | 24,697.6 | | | | 552,632 | | | | 131,743.2 | |
| Revisions of previous estimates | | | (7,354.5 | ) | | | (3,767.1 | ) | | | (138,923 | ) | | | (34,275.4 | ) |
| Improved recovery | | | — | | | | — | | | | — | | | | — | |
| Purchases of minerals in place | | | — | | | | 65.4 | | | | 1,403 | | | | 299.2 | |
| Extensions and Discoveries | | | 20.6 | | | | 158.7 | | | | 3,113 | | | | 698.1 | |
| Production | | | (985.3 | ) | | | (2,334.9 | ) | | | (62,081 | ) | | | (13,667.0 | ) |
| Sales of minerals in place | | | (176.1 | ) | | | (1,546.9 | ) | | | (32,299 | ) | | | (7,106.2 | ) |
| December 31, 2015 | | | 6,444.9 | | | | 17,272.8 | | | | 323,845 | | | | 77,691.9 | |
| | | | | | | | | | | | | | | | | |
| Proved Developed Reserves | | | | | | | | | | | | | | | | |
| Beginning of year | | | 7,789.2 | | | | 11,088.6 | | | | 240,356 | | | | 58,937.1 | |
| End of year | | | 3,865.7 | | | | 8,926.3 | | | | 168,903 | | | | 40,942.5 | |
| Proved Undeveloped Reserves | | | | | | | | | | | | | | | | |
| Beginning of year | | | 7,151.2 | | | | 13,609.0 | | | | 312,275 | | | | 72,806.0 | |
| End of year | | | 2,579.2 | | | | 8,346.5 | | | | 154,942 | | | | 36,749.4 | |
| Total(2) | | | 6,444.9 | | | | 17,272.8 | | | | 323,845 | | | | 77,691.6 | |
(1) Columns may not add due to rounding.
(2) Bellatrix does not file any estimates of total net proved crude oil or natural gas reserves with any U.S. federal authority or agency other than the SEC.
The reconciliation of Bellatrix reserves from 2015 to 2016 includes positive Revisions of over 13% of opening balance reserves. These Revisions are due to new wells exceeding expectations and existing wells outperforming the reserves assigned in the previous year. Additionally, gas shrink in the Company’s major operating field was decreased year-over-year with the movement of production to the Company’s new operating gas plant, adding sales volumes as a proportion of raw volumes overall.
Bellatrix continued development of it Spirit River natural gas play in 2016. The quantity of reserves attributed to Extensions and Discoveries was substantial at 19% of opening balance reserves. Success was due not only to the highly successful development program referenced above, but due to competitor development of offsetting lands helping to define the extent of the play and extend the proven component of the Company’s reserves over additional lands.
The Corporation completed the partial acquisition / buy-up of its joint venture partner’s production during the year and also swapped lands with various other partners to consolidate and increase its operating position in its core Ferrier Spirit River play. Offsetting this activity, property divestments occurred in several non-core properties, including the Pembina Cardium oil property and the Harmattan Cardium oil and Mannville gas property. Purchases and Sales largely offset each other at 8% and 11% of the opening reserve balance.
CAPITALIZED COSTS
| As at December 31, (in thousands of Canadian dollars) | | 2016 | | | 2015 | |
| Proved oil and gas properties | | | 2,091,014 | | | | 2,670,733 | |
| Unproved oil and gas properties | | | 29,246 | | | | 87,919 | |
| Total capitalized costs | | | 2,120,260 | | | | 2,758,652 | |
| Accumulated depletion and depreciation | | | (808,643 | ) | | | (1,213,043 | ) |
| Net capitalized costs | | | 1,311,617 | | | | 1,545,609 | |
COSTS INCURRED
| For the years ended December 31, (in thousands of Canadian dollars) | | 2016 | | | 2015 | |
| Property acquisition (disposition) costs(1) | | | | | | | | |
| Proved oil and gas properties | | | (299,067 | ) | | | (14,400 | ) |
| Unproved oil and gas properties | | | 2,635 | | | | 5,317 | |
| Exploratory costs(2) | | | 336 | | | | 661 | |
| Development costs(3) | | | 75,689 | | | | 149,173 | |
| Capital expenditures | | | (220,407 | ) | | | 140,751 | |
(1) Acquisitions are net of dispositions of properties.
(2) Cost of geological and geophysical capital expenditures and costs on exploratory plays.
(3) Includes equipping and facilities capital expenditures.
| For the years ended December 31, (in thousands of Canadian dollars) | | 2016 | | | 2015 | |
| Revenue, net of royalties and commodity contracts | | | 199,605 | | | | 319,990 | |
| Production costs | | | (113,589 | ) | | | (118,880 | ) |
| Transportation costs | | | (12,108 | ) | | | (17,146 | ) |
| Depletion, depreciation and impairment | | | 127,482 | | | | (697,633 | ) |
| Income taxes(1) | | | — | | | | — | |
| Results of operations | | | 201,390 | | | | (513,669 | ) |
(1) Bellatrix is currently not cash taxable.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN
The standardized measure of discounted future net cash flows is based on estimates made by InSite of net proved reserves. Future cash inflows are computed based on constant prices and cost assumptions applied against annual future production from proved crude oil and gas reserves. Future development and production costs are based on constant price assumptions and assume the continuation of existing economic conditions. Constant prices are the average of the first day prices of each month for the prior calendar 12 month period. Future income taxes are calculated by applying statutory income tax rates. Bellatrix is currently not cash taxable. The standardized measure of discounted future net cash flows is computed using a 10 percent discount factor.
Bellatrix cautions users of this information that the discounted future net cash flows relating to proved oil and gas reserves are neither an indication of the fair market value of our oil and gas properties, nor of the future net cash flows expected to be generated from such properties. The discounted future cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in crude oil and natural gas prices, development, asset retirement and production costs and possible changes to tax and royalty regulations. The prescribed discount rate of 10 percent is arbitrary and may not appropriately reflect future interest rates.
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows:
| (in thousands of Canadian dollars) | | 2016 | | | 2015 | |
| Future cash inflows | | | 1,432,343 | | | | 1,662,047 | |
| Future production costs(1) | | | 812,069 | | | | 738,063 | |
| Future development costs | | | 253,612 | | | | 375,748 | |
| Undiscounted pre-tax cash flows | | | 366,662 | | | | 548,236 | |
| Future income taxes(2) | | | — | | | | — | |
| Future net cash flows | | | 366,662 | | | | 548,236 | |
| Less 10% annual discount factor | | | 182,690 | | | | 184,652 | |
| Standardized measure of discounted future net cash flows | | | 183,972 | | | | 363,584 | |
(1) Future production costs include $11.3 million related to future abandonment and reclamation costs associated with wells having attributed reserves and for dedicated facilities required to produce these reserves. The estimate of future abandonment and reclamation costs excludes asset retirement obligations and reclamation costs relating to non-reserves wells and for non-dedicated gathering systems, batteries, plants and processing facilities. The incremental asset retirement obligation not included in the disclosure of estimated future net revenue is $86.7 million on an undiscounted basis.
(2) Bellatrix is currently not cash taxable.
The reconciliation of changes in standardized measure of future cash flows discounted at 10% per year relating to provide oil and gas reserves is as follows:
(in thousands of Canadian dollars, all changes except income taxes
pretax) | | 2016 | | | 2015 | |
| Standardized measure of discounted future net cash flows relating to proved oil and gas reserves, at beginning of year | | | 363,584 | | | | 1,439,679 | |
| Net change in sales and transfer prices related to future production(1) | | | (299,773 | ) | | | (1,044,179 | ) |
| Changes in estimated future development costs | | | (7,556 | ) | | | 15,131 | |
| Sales and transfers of oil and gas produced during the period(2) | | | (83,540 | ) | | | (163,838 | ) |
| Changes from extensions, discoveries, and improved recovery(3) | | | 29,554 | | | | 24,911 | |
| Changes from purchases of minerals in place(3) | | | 19,074 | | | | 518 | |
| Changes from dispositions of minerals in place(3) | | | (71,118 | ) | | | (68,373 | ) |
| Changes from revisions in quantity estimates(3) | | | 151,507 | | | | (131,849 | ) |
| Previously estimated development costs during the period | | | 28,500 | | | | 20,327 | |
| Accretion of discount(4) | | | 36,358 | | | | 143,968 | |
| Other(5) | | | 17,383 | | | | 2,987 | |
| Net change in income tax(6) | | | 0 | | | | 124,303 | |
| Standardized measure of discounted future net cash flows relating to proved oil and gas reserves, at end of year | | | 183,972 | | | | 363,584 | |
(1) The effect of changes in prices and costs has been computed before the effects of changes in quantities.
(2) Company actual before income taxes, excluding general and administrative expenses.
(3) Stated at prices used in estimating proved oil and gas reserves and year-end costs.
(4) The increase in the value of a discounted instrument as time passes. Calculated as 10 percent of net present value at the beginning of the period.
(5) Includes changes to actual prices received versus forecast, actual versus forecast production from the prior period, development timing, operating costs, and royalty rates.
(6) The net change in the estimate of future income taxes that will be due on future pretax net cash flows relating to proved oil and gas reserves.
