EX-13.4 5 exhibit134ogsupp.htm EXHIBIT 13.4 Exhibit


EXHIBIT 13.4
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, 2017 and 2016, 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, 2017, 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, 2017
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, 2016
 
983.4

 
19,477.8

 
401,814

 
87,430.2

Revisions of previous estimates
 
827.6

 
10,211.6

 
122,084

 
31,386.5

Improved recovery
 
—

 
—

 
—

 
—

Purchases of minerals in place
 
—

 
2,572.1

 
42,505

 
9,656.2

Extensions and Discoveries
 
7.9

 
5,572.3

 
90,505

 
20,664.4

Production
 
(171.9
)
 
(2,048.5
)
 
(53,750
)
 
(11,178.7
)
Sales of minerals in place
 
(262.3
)
 
(1,617.9
)
 
(36,429
)
 
(7,951.7
)
December 31, 2017
 
1,384.7

 
34,167.4

 
566,729

 
130,007.0

 
 
 
 
 
 
 
 
 
Proved Developed Reserves
 
 

 
 

 
 

 
 

Beginning of year
 
943.6

 
8,631.7

 
196,841

 
42,382.1

End of year
 
848.0

 
12,544.2

 
233,956

 
52,384.8

Proved Undeveloped Reserves
 
 
 
 
 
 
 
 
Beginning of year
 
39.8

 
10,846.2

 
204,973

 
45,048.1

End of year
 
536.7

 
21,623.2

 
332,773

 
77,622.1

Total (2)
 
1,384.7

 
34,167.4

 
566,729

 
130,007.0

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

____________________________________________________________________________
(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 2016 to 2017 includes positive revisions of previous estimates of 31,386.5 mboe from the previous year. 19,379.8 mboe of the total, or 62%, was due to increases in constant pricing which enabled previously uneconomic wells to recover in the current year. The remaining 12,006.7 mboe, or 38%, was due to new wells exceeding previous expectations and existing wells outperforming the reserves assigned in the previous year. In 2017, there were no material changes caused by proved undeveloped locations becoming uneconomic.

The reconciliation of Bellatrix reserves from 2015 to 2016 includes positive revisions of previous estimates of 10,038.8 mboe from the previous year. 9,668.2 mboe of the total, or 96%, was due to new wells exceeding previous expectations and existing wells outperforming the reserves assigned in the previous year, and the remaining revisions were due to a variety of immaterial factors, including gas shrinkage. In 2016, there were no material changes caused by proved undeveloped locations becoming uneconomic.
Bellatrix continued development of its Spirit River natural gas play in 2016 and 2017. The quantity of reserves attributed to Extensions and Discoveries was substantial at 19% and 24% of opening balance reserves for 2016 and 2017, respectively. In both years, producing extensions and additional reserves were 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.

In 2016, the Corporation completed the partial acquisition/buy-up of its joint venture partner’s production during the year and in 2016 and 2017 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, in 2016, the divestment of its Pembina Cardium oil property, Harmattan Cardium oil property and Mannville gas property and, in 2017, the divestment of a portion of its West Pembina Cardium oil property and its Strachan gas property. Purchases and Sales largely offset each other at 8% and 11% (2016) and 11% and 9% (2017) of the opening reserve balance.

CAPITALIZED COSTS
As at December 31, (in thousands of Canadian dollars)
 
2017
 
2016
Proved oil and gas properties
 
1,916,791

 
2,091,014

Unproved oil and gas properties
 
22,731

 
29,246

Total capitalized costs
 
1,939,522

 
2,120,260

Accumulated depletion and depreciation
 
(742,653
)
 
(808,643
)
Net capitalized costs
 
1,196,869

 
1,311,617


COSTS INCURRED
For the years ended December 31, (in thousands of Canadian dollars)
 
2017
 
2016
Property acquisition (disposition) costs (1)
 
 

 
 

Proved oil and gas properties
 
(48,684
)
 
(299,067
)
Unproved oil and gas properties
 
4,007

 
2,635

Exploratory costs (2)
 
818

 
336

Development costs (3)
 
116,326

 
75,689

Capital expenditures
 
72,467

 
(220,407
)
____________________________________________________________________________
(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)
 
2017
 
2016
Revenue, net of royalties and commodity contracts
 
302,000

 
199,605

Production costs
 
(111,816
)
 
(113,589
)
Transportation costs
 
(23,549
)
 
(12,108
)
Depletion, depreciation and impairment
 
(133,802
)
 
127,482

Income taxes (1)
 
—

 
—

Results of operations
 
32,833

 
201,390

____________________________________________________________________________
(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% 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)
 
2017
 
2016
Future cash inflows
 
2,603,521

 
1,432,343

Future production costs (1)
 
1,256,836

 
812,069

Future development costs
 
467,117

 
253,612

Undiscounted pre-tax cash flows
 
879,568

 
366,662

Future income taxes (2)
 
—

 
—

Future net cash flows
 
879,568

 
366,662

Less 10% annual discount factor
 
428,986

 
182,690

Standardized measure of discounted future net cash flows
 
450,582

 
183,972

____________________________________________________________________________
(1) Future production costs include 11.3 million (2016) and $13.6 million (2017) 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 was $13.8 million on a discounted basis and $86.7 million on an undiscounted basis in 2016, and $11.8 million on a discounted basis and $81.0 million on an undiscounted basis in 2017.
(2)Bellatrix's available tax pools exceed Bellatrix's cash flows.
The reconciliation of changes in standardized measure of future cash flows discounted at 10% per year relating to proved oil and gas reserves is as follows:




(in thousands of Canadian dollars, all changes except income taxes
pretax)
 
2017
 
2016
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves, at beginning of year
 
183,972

 
363,584

Net change in sales and transfer prices related to future production (1)
 
195,827

 
(299,773
)
Changes in estimated future development costs
 
(46,872
)
 
(7,556
)
Sales and transfers of oil and gas produced during the period (2)
 
(84,500
)
 
(83,540
)
Changes from extensions, discoveries, and improved recovery (3)
 
67,974

 
29,554

Changes from purchases of minerals in place (3)
 
41,144

 
19,074

Changes from dispositions of minerals in place (3)
 
(22,879
)
 
(71,118
)
Changes from revisions in quantity estimates (3)
 
59,774

 
151,507

Previously estimated development costs during the period
 
22,181

 
28,500

Accretion of discount (4)
 
18,397

 
36,358

Other (5)
 
15,564

 
17,383

Net change in income tax (6)
 
—

 
—

Standardized measure of discounted future net cash flows relating to proved oil and gas reserves, at end of year
 
450,582

 
183,972

____________________________________________________________________________
(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% 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.