Exhibit 99.4
BELLATRIX EXPLORATION LTD.
SUPPLEMENTARY OIL AND GAS INFORMATION - (UNAUDITED)
The following disclosures in this section provide oil and gas information in accordance with the U.S. standard, “Extractive Industries - Oil and Gas”. Bellatrix Exploration Ltd. (“Bellatrix”) prepares its consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”).
NET PROVED OIL AND NATURAL GAS RESERVES
Bellatrix engaged an independent qualified reserve evaluator, Sproule Associates Ltd. (“Sproule”), to evaluate Bellatrix’s proved developed and proved undeveloped oil and natural gas reserves. As at December 31, 2013, 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, 2013
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, 2012 | 8,807 | 5,496 | 164,182 | 41,667 |
| Revisions of previous estimates | 346 | 1,317 | 47,277 | 9,543 |
| Improved recovery | 249 | 170 | 2,321 | 806 |
| Purchases of minerals in place | 5,968 | 7,287 | 71,149 | 25,113 |
| Extensions and Discoveries | 1,653 | 4,287 | 123,765 | 26,568 |
| Production | (883) | (1,112) | (27,686) | (6,609) |
| Sales of minerals in place | (172) | (31) | (2,160) | (563) |
December 31, 2013 | 15,967 | 17,414 | 378,848 | 96,522 |
| | | | | |
| Proved Developed Reserves | | | | |
| Beginning of year | 4,326 | 2,093 | 66,718 | 17,539 |
| End of year | 7,752 | 7,839 | 152,781 | 41,055 |
| Proved Undeveloped Reserves | | | | |
| Beginning of year | 4,481 | 3,403 | 97,464 | 24,128 |
| End of year | 8,215 | 9,575 | 226,067 | 55,468 |
Total(2) | 15,967 | 17,414 | 378,848 | 96,522 |
YEAR ENDED DECEMBER 31, 2012
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, 2011 | 7,820 | 3,682 | 116,722 | 30,955 |
| Revisions of previous estimates | 496 | 632 | 18,354 | 4,187 |
| Improved recovery | 464 | 144 | 3,639 | 1,214 |
| Purchases of minerals in place | 223 | 194 | 5,139 | 1,274 |
| Extensions and Discoveries | 1,216 | 1,455 | 43,815 | 9,973 |
| Production | (953) | (611) | (23,469) | (5,475) |
| Sales of minerals in place | (459) | - | (18) | (462) |
December 31, 2012 | 8,807 | 5,496 | 164,182 | 41,667 |
| | | | | |
| Proved Developed Reserves | | | | |
| Beginning of year | 4,056 | 1,504 | 53,618 | 14,496 |
| End of year | 4,326 | 2,093 | 66,718 | 17,539 |
| Proved Undeveloped Reserves | | | | |
| Beginning of year | 3,765 | 2,177 | 63,104 | 16,459 |
| End of year | 4,481 | 3,403 | 97,464 | 24,128 |
Total(2) | 8,807 | 5,496 | 164,182 | 41,667 |
(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.
CAPITALIZED COSTS
| | |
| As at December 31, (in thousands of Canadian dollars) | 2013 | 2012 |
| Proved oil and gas properties | 1,629,027 | 851,108 |
| Unproved oil and gas properties | 132,971 | 38,177 |
| Total capitalized costs | 1,761,998 | 889,285 |
| Accumulated depletion and depreciation | (344,962) | (262,570) |
| Net capitalized costs | 1,417,036 | 626,715 |
COSTS INCURRED
| | |
| For the years ended December 31, (in thousands of Canadian dollars) | 2013 | 2012 |
| Property acquisition (disposition) costs (1) | | |
| Proved oil and gas properties | (57,556) | 14,306 |
| Unproved oil and gas properties | 11,190 | 8,303 |
| Exploratory costs(2) | 140 | 290 |
| Development costs(3) | 269,679 | 155,594 |
| Capital expenditures | 223,453 | 178,493 |
(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.
RESULTS OF OPERATIONS OF PRODUCING ACTIVITIES
| | |
| For the years ended December 31, (in thousands of Canadian dollars) | 2013 | 2012 |
| Revenue, net of royalties and commodity contracts | 230,406 | 202,633 |
| Production costs | (69,668) | (53,316) |
| Transportation costs | (7,014) | (4,978) |
| Depletion and depreciation | (85,829) | (75,720) |
| Income taxes(1) | - | - |
| Results of operations | 67,895 | 68,619 |
(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 Sproule 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 natural 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.
| | |
| (in thousands of Canadian dollars) | 2013 | 2012 |
| Future cash inflows | 4,707,314 | 1,890,486 |
| Future production costs | (2,145,843) | (896,024) |
| Future development costs | (747,469) | (309,582) |
| Undiscounted pre-tax cash flows | 1,814,002 | 684,880 |
| Future income taxes(1) | (153,827) | (29,366) |
| Future net cash flows | 1,660,175 | 655,514 |
| Less 10% annual discount factor | (713,655) | (271,054) |
| Standardized measure of discounted future net cash flows | 946,520 | 384,460 |
(1) Bellatrix is currently not cash taxable.
| | |
| (in thousands of Canadian dollars, all changes except income taxes pretax) | 2013 | 2012 |
| Estimated future net revenue at beginning of year | 384,460 | 382,284 |
| Net change in sales and transfer prices related to future production(1) | 66,951 | (160,239) |
| Changes in estimated future development costs | (370,769) | (45,271) |
| Sales and transfers of oil and gas produced during the period(2) | (168,992) | (122,264) |
| Changes from extensions, discoveries, and improved recovery(3) | 214,966 | 170,915 |
| Changes from purchases of minerals in place(3) | 275,809 | 22,753 |
| Changes from dispositions of minerals in place(3) | (7,886) | (6,762) |
| Changes from revisions in quantity estimates(3) | 510,022 | 128,091 |
| Previously estimated development costs during the period | 66,880 | 24,150 |
| Accretion of discount(4) | (38,446) | (39,861) |
| Other(5) | 59,671 | 22,473 |
| Net change in income tax(6) | (46,146) | 8,191 |
| Estimated future net revenue at end of year | 946,520 | 384,460 |
(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) Estimated as 10 percent of the beginning of period net present value.
(5) Includes changes to development timing, operating costs, royalty rates, and actual prices received versus forecast.
(6) Income taxes incurred during the period as well as change in future income tax expenses.
