CALGARY, Feb. 10, 2015 /CNW/ – Yangarra Resources Ltd. (“Yangarra” or the“Company”) (TSX:YGR) releases the results of its 2014 year end oil and gas reserves evaluation, provides an operations update and a 2015 outlook.
Reserve Report Highlights:
The financial and operational information below is based on estimates and are unaudited.
Developed producing reserves (“PDP”)
Total Proved reserves (“1P”)
Proved plus probable reserves (“2P”)
Other Information
Operations Update
With the steep decline in commodity prices late last year, the Company shut down its contracted drilling rig November 6, 2014, re-mobilized the rig to drill one Cardium well in January 2015 and then sent the rig back to the rack site. With significant discounts recently offered by service providers the Company plans to drill 2-3 more wells prior to break up. Completion of these wells will likely be deferred until the second quarter.
Current production is approximately 3,000 boe/d with minor infrastructure issues still being encountered. The Company expects that lower commodity pricing will ultimately alleviate most of those issues similar to previous downturns.
2015 Outlook
Yangarra focused the $78 million of capital budget in 2014 on validating Cardium acreage, and proving our down spacing strategy. The Company booked 132 future Cardium locations in the reserve report (45% of identified locations) increasing the 2P Reserve Life Index (“RLI”) to 34 years reflecting the success of the 2014 drilling program. Yangarra is now positioned to transition into low risk Cardium development drilling. As full cycle economics improve through a combination of reduced service costs and higher commodity pricing, the Company is positioned to accelerate the drilling program significantly over the next couple of years.
During 2014, the Company experienced success in keeping its cost structure with low operating costs and low G&A costs, as well as maintaining a royalty cost advantage. These measures are much more meaningful in the current commodity pricing environment, giving Yangarra the advantage of higher relative cash netbacks.
The September 2013 farm-in is progressing with 2.55 earning wells required in 2015. The Company expects to drill and earn an additional 5-7 sections prior to the sunset clause in the agreement as at December 31, 2016.
Yangarra continues to manage the balance sheet and is targeting debt to cash flow of 2 to 1 or less in 2015 (assuming current strip pricing). Full year debt to cash flow in 2014 was approximately 1.5 to 1.0. The hedging program has provided excellent coverage in this low commodity environment which together with many other cost cutting initiatives will assist with keeping the balance sheet strong. Yangarra continues to make all capital allocation decisions based on maximizing full cycle economics.
Oil and Gas Reserves
The following tables summarize certain information contained in the independent reserves report prepared by AJM Deloitte dated February 10, 2015 and effective as of December 31, 2014. The report was prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”).
AJM Deloitte is using a price forecast of US$67/bbl WTI and US$70/bbl WTI for light oil for 2015 and 2016, respectively, and $3.85/mcf and $4.05/mcf for AECO natural gas in 2015 and 2016, respectively.
Summary of Oil and Gas Reserves
(Company Share Gross volumes based on forecast price and costs)
|
Reserves Category
|
||||||||||
|
Light and Medium Oil (Mbbl) |
Natural Gas Liquids (Mbbl) |
Natural Gas (MMcf) |
Total BOE 2014 (Mboe) |
Total BOE 2013 (Mboe) |
||||||
|
Proved Developed Producing |
1,569 |
1,037 |
19,454 |
5,849 |
3,949 |
|||||
|
Proved Developed Non-Producing |
8 |
32 |
2,196 |
406 |
563 |
|||||
|
Proved Undeveloped |
4,363 |
2,403 |
44,661 |
14,210 |
4,929 |
|||||
|
Total Proved |
5,941 |
3,472 |
66,310 |
20,465 |
9,441 |
|||||
|
Probable |
3,998 |
3,076 |
59,378 |
16,971 |
8,023 |
|||||
|
Total Proved Plus Probable |
9,939 |
6,548 |
125,688 |
37,435 |
17,464 |
|||||
|
Notes to table: |
|
|
(1) |
Total values may not add due to rounding. |
|
|
(2) |
BOEs are derived by converting gas to oil equivalent in the ratio of six thousand cubic feet of gas to one barrel of oil (6 Mcf:1 bbl). |
|
|
(3) |
“Company Share Gross” reserves are the Company’s working interest (operating or non-operating) share and before deducting royalty obligations but including any royalty interests of the Company. |
Summary of Net Present Values of Future Net Revenue (Before Tax)
(based on forecast price and costs)
|
As At December 31, 2014(2) |
As At |
|||||||||
|
Reserves Category |
0.0% (M$) |
5.0% (M$) |
10.0% (M$) |
15.0% (M$) |
20.0% (M$) |
10% (M$) |
||||
|
Proved Developed Producing |
143,474 |
117,498 |
99,586 |
86,688 |
77,050 |
78,259 |
||||
|
Proved Developed Non-Producing |
5,339 |
4,302 |
3,561 |
3,013 |
2,595 |
14,239 |
||||
|
Proved Undeveloped |
285,273 |
184,628 |
122,234 |
81,559 |
53,919 |
54,859 |
||||
|
Total Proved |
434,086 |
306,429 |
225,380 |
171,261 |
133,565 |
147,357 |
||||
|
Probable |
488,022 |
275,572 |
169,747 |
111,263 |
76,161 |
103,791 |
||||
|
Total Proved Plus Probable |
922,108 |
582,001 |
395,128 |
282,523 |
209,726 |
251,148 |
||||
|
Notes to table: |
|
|
(1) |
Total values may not add due to rounding. |
|
|
(2) |
Forecast pricing used is based on AJM Deloitte published price forecasts effective December 31, 2014. |
|
|
(3) |
Forecast pricing used is based on AJM Deloitte published price forecasts effective December 31, 2013. |
|
|
(4) |
Cash flows include the effects of the current Alberta Royalty Framework. The estimated future net reserves are stated before deducting future estimated site restoration costs and are reduced for future abandonment costs and estimated capital for future development associated with the reserves. |
|
|
(5) |
It should not be assumed that the net present values of future net revenues estimated by AJM Deloitte represent fair market value of the reserves. There is no assurance that the forecast price and cost assumptions will be attained and variances could be material. |
|
Reserve Definitions: |
|
|
(a) |
“Proved” reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. |
|
|
(b) |
“Probable” reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. |
|
|
(c) |
“Developed” reserves are those 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 (e.g. when compared to the cost of drilling a well) to put the reserves on production. |
|
|
(d) |
“Developed Producing” reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. |
|
|
(e) |
“Developed Non-Producing” reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown. |
|
|
(f) |
“Undeveloped” reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. |
|
|
(g) |
The Net Present Value (NPV) is based on AJM Deloitte Forecast Pricing and costs. The estimated NPV does not necessarily represent the fair market value of our reserves. There is no assurance that forecast prices and costs assumed in the AJM Deloitte evaluations will be attained, and variances could be material. |
Finding and Development Costs (“F&D”)
Yangarra’s F&D costs for 2014, 2013 and the three year average are presented in the tables below. The costs used in the F&D calculation are the capital costs related to: land acquisition and retention; drilling; completions; tangible well site; tie-ins; and facilities, plus the change in estimated future development costs as per the independent reserve report. Acquisition costs are net of any proceeds from dispositions of properties. Due to the timing of capital costs and the subjectivity in the estimation of future costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. The reserves used in this calculation are Company net reserve additions, including revisions.
Proved Finding & Development Costs ($ millions)
|
2014 |
2013 |
2012 – 2014 |
||
|
Capital expenditures |
78.0 |
47.0 |
144.8 |
|
|
Change in future capital |
133.7 |
7.2 |
164.7 |
|
|
Total capital for F&D |
211.7 |
54.2 |
309.5 |
|
|
Reserve additions, net production (Mboe) |
12,084 |
3,083 |
17,575 |
|
|
Proved F&D costs – including future capital ($/boe) |
17.52 |
17.58 |
17.61 |
|
|
Proved F&D costs – excluding future capital ($/boe) |
6.46 |
15.25 |
8.24 |
|
|
Proved Recycle Ratio |
||||
|
Including future capital |
2.42 |
2.06 |
||
|
Excluding future capital |
6.56 |
2.37 |
||
Proved plus Probable Finding & Development Costs ($ millions)
|
2014 |
2013 |
2012 – 2014 |
||
|
Capital expenditures |
78.0 |
47.0 |
144.8 |
|
|
Change in future capital |
172.6 |
33.9 |
242.2 |
|
|
Total capital for F&D |
250.6 |
80.9 |
387.0 |
|
|
Reserve additions, net production (Mboe) |
21,031 |
5,750 |
31,240 |
|
|
Proved plus Probable F&D costs – including future capital ($/boe) |
11.92 |
14.07 |
12.39 |
|
|
Proved plus Probable F&D costs – excluding future capital ($/boe) |
3.71 |
8.18 |
4.64 |
|
|
Proved plus Probable Recycle Ratio |
||||
|
Including future capital |
3.55 |
2.57 |
||
|
Excluding future capital |
11.41 |
4.42 |
||
Net Asset Value (“NAV”)
|
As at December 31, 2014 |
Total Proved |
Proved + Probable |
||
|
Present Value Reserves, before tax (discounted at 10%) ($ million) |
$ |
225.4 |
$ |
395.1 |
|
Total Debt ($ million) |
(58.0) |
(58.0) |
||
|
Net Asset Value |
$ |
167.4 |
$ |
337.1 |
|
Common shares outstanding at year end (million) |
57.7 |
57.7 |
||
|
Net asset value per share |
$ |
2.90 |
$ |
5.84 |
|
Notes to tables: |
|
|
(1) |
The preceding table shows what is customarily referred to as a “produce out” net asset value calculation under which the current value of Yangarra’s reserves would be produced at the AJM Deloitte forecast future prices and costs. The value is a snapshot in time as at December 31, 2014 and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. In this analysis, the present value of the proved and probable reserves is calculated at a before tax 10 percent discount rate. |
|
|
(2) |
The 2014 total debt, excludes non-cash items (MTM on commodity contracts and Flow through share obligations). |
|
[expand title=”Advisories & Contact”]
Year End Disclosure
The Company is planning to release its 2014 year-end financial and operating results late March 2015.
Additional reserve information as required under NI 51-101 will be included in the Company’s Annual Information Form which will be filed on SEDAR by March 31, 2015.
Natural gas has been converted to a barrel of oil equivalent (Boe) using 6,000 cubic feet (6 Mcf) of natural gas equal to one barrel of oil (6:1), unless otherwise stated. The Boe conversion ratio of 6 Mcf to 1 Bbl is based on an energy equivalency conversion method and does not represent a value equivalency; therefore Boe’s may be misleading if used in isolation. References to natural gas liquids (“NGLs”) in this news release include condensate, propane, butane and ethane and one barrel of NGLs is considered to be equivalent to one barrel of crude oil equivalent (Boe). One (“BCF”) equals one billion cubic feet of natural gas. One (“Mmcf”) equals one million cubic feet of natural gas.
Certain information regarding Yangarra set forth in this news release, including management’s assessment of future plans, operations and operational results may constitute forward-looking statements under applicable securities law and necessarily involve risks associated with oil and gas exploration, production, marketing and transportation such as loss of market, volatility of prices, currency fluctuations, imprecision of reserves estimates, environmental risks, competition from other producers and ability to access sufficient capital from internal and external sources. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements.
The initial production rates discussed in this press release are not necessarily indicative of long-term performance or of ultimate recovery due to high initial decline rates.
All reference to $ (funds) are in Canadian dollars.
Neither the TSX nor its Regulation Service Provider (as that term is defined in the Policies of the TSX) accepts responsibility for the adequacy and accuracy of this release.
SOURCE Yangarra Resources Ltd.