CALGARY, March 25, 2014 /CNW/ - Yangarra Resources Ltd. ("Yangarra" or the "Company") (TSX-V:YGR) releases its 2013 financials and reserves.
2013 Financial and Operating Highlights
During the year ended December 31, 2013 the Company completed the following significant milestones:
Reserve Report Highlights:
Operations Update
During the first quarter of 2014 the Company drilled 6 gross (5.9 net) wells in the Cardium formation. A total of 4 gross (3.9 net) wells were put on production during the quarter with the final 2 (2.0 net) expected to be on stream at quarter end. The Company experienced 11 days of shut-in production (approximately 1,200 boe/d) due to the TransCanada pipeline rupture near Rocky Mountain House and an additional 150 boe/d average for the quarter of Keyera curtailments at other facilities. The Company expects first quarter production to be approximately 2,800 boe/d and full year guidance remains at 3,200 boe/d. The Company will continue to drill through break-up as conditions permit, with 6 gross (5.2 net) wells planned for the second quarter.
President's Message to Shareholders
Yangarra is currently drilling its 71st horizontal well in Central Alberta. The experience gained by drilling this many wells with the team we have put in place over the past four years has been key to reducing costs to a point where we are top decile in drilling and completions, operating costs and G&A costs. We are currently concentrating on "oilier" targets in the Cardium and Glauconite horizons where we have significant inventory. We also have a large undrilled inventory in "gassier" Cardium, Glauconite and Rock Creek zones that we will drill as natural gas prices continue to improve. These "gassier" targets are extremely "liquids rich", however, the "oilier" targets still command higher internal rates of return (IRR). Half cycle IRR's in 2013 were 65%, re-cycle ratios were 2.57 (P+P including changes in future capital) in 2013 and annual production growth is forecast to be 45% in 2014.
A recent farm-in was negotiated in which the Company added significant acreage to its Cardium inventory. Yangarra has been active at crown land sales and has been successful closing deals with industry to add additional future drilling locations. The Company has added two future drilling locations for every location drilled in each of the past four years and we have visibility to do the same going forward.
Yangarra is focused on adding shareholder value and to properly gauge this we have calculated full-cycle rates of return, presented below which we believe is more indicative of value creation. All capital costs for each year are included in this calculation including land, infrastructure, geological work, etc. The chart shows the impact of focusing on returns rather than focusing on growth.
According to Yangarra's 2013 year end engineering report the Company is valued at $1.40 per share (2P (pre-tax) at PV 10, net of debt). The financing late last year provided the necessary liquidity to achieve the outstanding reserve additions generated by the Company in the fourth quarter of 2013. There is significant additional intrinsic value not booked in the reserve report in our 53,000 acres (including farm-in acreage) of undeveloped Cardium and Glauconite land and for our 39,040 acre net Duvernay land position.
TD Bank recently opined that liquids rich Duvernay lands may be worth $2,000 - $4,000 per acre in Pembina/Willesden Green which positions our shareholders with great option value in this rapidly developing play. Yangarra has recently retained the services of two experienced shale professionals to develop the asset with plans in progress to drill a vertical strata-graphic test well.
I would like to thank the shareholders for their support. I thank my colleagues at Yangarra for their ongoing dedication to the development of the Company. They have delivered seamless, reliable operations and demonstrated their ability to quickly interpret, react and adapt to the technical results of our development drilling efforts. I also wish to take this opportunity to thank my fellow directors for their support and leadership.
Financial Summary
| 2013 | 2012 | Year ended | ||||||||||||||||
| Q4 | Q3 | Q4 | 2013 | 2012 | 2011 | |||||||||||||
| Statements of Comprehensive Income (Loss) | ||||||||||||||||||
| Petroleum & natural gas sales | $ | 11,087,956 | $ | 9,372,931 | $ | 4,842,343 | $ | 34,726,657 | $ | 21,327,157 | $ | 20,742,259 | ||||||
| Net income (loss) for the period (before tax) | $ | 1,576,908 | $ | 39,646 | $ | (2,409,766) | $ | 4,146,706 | $ | 21,174 | $ | 4,872,697 | ||||||
| Net income (loss) for the period | $ | 750,851 | $ | 11,330 | $ | 340,623 | $ | 2,585,699 | $ | (217,712) | $ | 1,385,698 | ||||||
| Net income (loss) per share - basic and diluted | $ | 0.01 | $ | 0.00 | $ | 0.00 | $ | 0.02 | $ | (0.00) | $ | 0.01 | ||||||
| Statements of Cash Flow | ||||||||||||||||||
| Funds flow from (used in) operating activities | $ | 7,975,588 | $ | 6,378,207 | $ | 3,168,328 | $ | 25,648,666 | $ | 14,588,405 | $ | 16,341,180 | ||||||
| Funds flow from (used in) operating activities per share - basic and diluted | $ | 0.06 | $ | 0.05 | $ | 0.03 | $ | 0.21 | $ | 0.12 | $ | 0.15 | ||||||
| Cash from (used in) operating activities | $ | 10,757,178 | $ | 3,683,552 | $ | 4,163,347 | $ | 27,077,123 | $ | 17,016,431 | $ | 6,664,849 | ||||||
| Statements of Financial Position | ||||||||||||||||||
| Property and equipment | $ | 152,971,016 | $ | 135,892,343 | $ | 121,842,378 | $ | 152,971,016 | $ | 121,842,378 | $ | 119,374,219 | ||||||
| Total assets | $ | 169,798,021 | $ | 154,773,403 | $ | 138,894,114 | $ | 169,798,021 | $ | 138,894,114 | $ | 141,291,043 | ||||||
| Working Capital (deficit), excluding MTM on commodity contracts | $ | 36,794,243 | $ | 42,594,542 | $ | (36,301,842) | $ | 36,794,243 | $ | (36,301,842) | $ | (34,028,162) | ||||||
| Subordinated Debt | $ | 7,786,632 | $ | - | $ | - | $ | 7,786,632 | $ | - | $ | - | ||||||
| Non-Current Liabilities | $ | 7,523,351 | $ | 13,971,180 | $ | 12,274,710 | $ | 7,523,351 | $ | (12,274,710) | $ | (9,752,766) | ||||||
| Shareholders equity | $ | 95,583,587 | $ | 82,022,213 | $ | 79,689,765 | $ | 95,583,587 | $ | (79,689,765) | $ | (76,627,244) | ||||||
| Weighted average number of shares - basic | 127,219,336 | 121,718,245 | 121,711,723 | 123,101,587 | 120,663,095 | 105,960,324 | ||||||||||||
| Weighted average number of shares diluted | 128,322,269 | 121,987,009 | 121,711,723 | 123,101,587 | 120,663,095 | 113,781,122 | ||||||||||||
Operations Summary
| 2013 | 2012 | Year Ended | |||||||||||||||
| Q4 | Q3 | Q4 | 2013 | 2012 | |||||||||||||
| Daily production volumes | |||||||||||||||||
| Natural gas (mcf/d) | 8,303 | 6,983 | 4,607 | 6,583 | 5,586 | ||||||||||||
| Oil (bbl/d) | 683 | 547 | 418 | 556 | 350 | ||||||||||||
| NGL's (bbl/d) | 605 | 450 | 304 | 422 | 341 | ||||||||||||
| Royalty income | |||||||||||||||||
| Natural gas (mcf/d) | 405 | 299 | 956 | 557 | 1,273 | ||||||||||||
| Oil (bbl/d) | 1 | 1 | (7) | 1 | 3 | ||||||||||||
| NGL's (bbl/d) | 24 | 26 | 57 | 37 | 77 | ||||||||||||
| Combined (boe/d 6:1) | 2,764 | 2,238 | 1,700 | 2,206 | 1,914 | ||||||||||||
| Revenue | |||||||||||||||||
| Petroleum & natural gas sales - Gross | $ | 11,087,956 | $ | 9,372,931 | $ | 4,842,343 | $ | 34,726,657 | $ | 21,327,157 | |||||||
| Royalty income | 177,335 | 195,468 | 216,693 | 1,108,750 | 2,024,819 | ||||||||||||
| Commodity contract settlement | 271,387 | (326,435) | 535,585 | 1,181,080 | 907,863 | ||||||||||||
| Total sales | 11,536,678 | 9,241,964 | 5,594,621 | 37,016,487 | 24,259,839 | ||||||||||||
| Royalty expense | (557,278) | (701,597) | (3,370) | (1,796,832) | (1,057,597) | ||||||||||||
| Petroleum & natural gas sales - Net | $ | 10,979,400 | $ | 8,540,367 | $ | 5,591,251 | $ | 35,219,655 | $ | 23,202,242 | |||||||
| Change in fair value of contracts | $ | (2,217,286) | $ | (2,411,102) | $ | (209,267) | $ | (6,928,607) | $ | 3,889,986 | |||||||
| Total Revenue - Net of royalties | $ | 8,762,114 | $ | 6,129,265 | $ | 5,381,984 | $ | 28,291,048 | $ | 27,092,228 | |||||||
Pricing Summary
| 2013 | 2012 | Year Ended | |||||||||||||||||||
| Q4 | Q3 | Q4 | 2013 | 2012 | |||||||||||||||||
| Realized Pricing (Including commodity contracts) | |||||||||||||||||||||
| Oil ($/bbl) | $ | 85.56 | $ | 96.51 | $ | 83.76 | $ | 92.08 | $ | 84.09 | |||||||||||
| NGL ($/bbl) | $ | 52.08 | $ | 53.33 | $ | 25.09 | $ | 54.32 | $ | 46.78 | |||||||||||
| Gas ($/mcf) | $ | 3.92 | $ | 3.05 | $ | 3.02 | $ | 3.53 | $ | 2.49 | |||||||||||
| Realized Pricing (Excluding commodity contracts) | |||||||||||||||||||||
| Oil ($/bbl) | $ | 84.98 | $ | 102.99 | $ | 77.78 | $ | 90.93 | $ | 83.07 | |||||||||||
| NGL ($/bbl) | $ | 51.45 | $ | 60.77 | $ | 18.27 | $ | 52.91 | $ | 45.92 | |||||||||||
| Gas ($/mcf) | $ | 3.67 | $ | 2.57 | $ | 2.94 | $ | 3.25 | $ | 2.23 | |||||||||||
| Oil Price Benchmarks | |||||||||||||||||||||
| West Texas Intermediate ("WTI") (US$/bbl) | $ | 97.46 | $ | 105.81 | $ | 88.22 | $ | 97.97 | $ | 94.21 | |||||||||||
| Edmonton (C$/bbl) | $ | 86.58 | $ | 103.65 | $ | 83.99 | $ | 93.11 | $ | 87.02 | |||||||||||
| Natural Gas Price Benchmarks | |||||||||||||||||||||
| AECO gas (Cdn$/GJ) | $ | 3.15 | $ | 2.82 | $ | 3.06 | $ | 3.65 | $ | 2.79 | |||||||||||
| Foreign Exchange | |||||||||||||||||||||
| U.S./Canadian Dollar Exchange | $ | 0.953 | $ | 0.963 | $ | 1.009 | $ | 0.971 | $ | 1.000 | |||||||||||
Netback Summary
| 2013 | 2012 | Year Ended | |||||||||||||||||||||||||
| Q4 | Q3 | Q4 | 2013 | 2012 | |||||||||||||||||||||||
| Sales Price | $ | 44.67 | $ | 43.94 | $ | 34.39 | $ | 44.59 | $ | 31.74 | |||||||||||||||||
| Royalty income | 0.70 | 0.95 | 1.39 | 1.38 | 2.89 | ||||||||||||||||||||||
| Royalty expense | (2.19) | (3.41) | (0.02) | (2.23) | (1.51) | ||||||||||||||||||||||
| Production costs | (6.20) | (5.45) | (9.65) | (6.30) | (6.81) | ||||||||||||||||||||||
| Transportation costs | (1.27) | (1.47) | (0.95) | (1.26) | (0.84) | ||||||||||||||||||||||
| Operating netback | $ | 35.70 | $ | 34.56 | $ | 25.16 | $ | 36.18 | $ | 25.48 | |||||||||||||||||
| G&A and other (excludes non-cash items) | (2.07) | (1.76) | (2.25) | (2.06) | (2.52) | ||||||||||||||||||||||
| Finance expenses | (2.59) | (2.32) | (2.65) | (2.32) | (2.13) | ||||||||||||||||||||||
| Cash flow netback | 31.04 | 30.49 | 20.26 | 31.80 | 20.82 | ||||||||||||||||||||||
| Depletion and depreciation | (15.96) | (18.05) | (18.52) | (17.50) | (20.67) | ||||||||||||||||||||||
| Impairment | - | - | (19.82) | - | (5.76) | ||||||||||||||||||||||
| Gain on sale of property and equipment | - | - | 4.15 | - | 0.93 | ||||||||||||||||||||||
| Accretion | (0.16) | (0.15) | (0.14) | (0.18) | (0.13) | ||||||||||||||||||||||
| Stock-based compensation | - | (0.38) | - | (0.36) | (0.71) | ||||||||||||||||||||||
| Unrealized gain (loss) on financial instruments | (8.72) | (11.71) | (1.34) | (8.60) | 5.55 | ||||||||||||||||||||||
| Deferred income tax | (3.25) | (0.14) | 17.59 | (1.94) | (0.34) | ||||||||||||||||||||||
| Net Income (loss) netback | $ | 2.95 | $ | 0.06 | $ | 2.18 | $ | 3.21 | $ | (0.31) | |||||||||||||||||
Capital Summary
| 2013 | 2012 | Year Ended | ||||||||||||||||||||||
| Cash Additions | Q4 | Q3 | Q4 | 2013 | 2012 | |||||||||||||||||||
| Land, acquisitions and lease rentals | $ | (261,263) | $ | 307,274 | $ | 240,777 | $ | 184,606 | $ | 734,910 | ||||||||||||||
| Drilling and completion | 18,958,090 | 6,725,516 | 6,679,886 | 35,705,499 | 19,727,708 | |||||||||||||||||||
| Geological and geophysical | 170,565 | 417,101 | 337,060 | 756,870 | 1,002,064 | |||||||||||||||||||
| Equipment | 1,490,863 | 1,036,654 | 1,758,120 | 7,595,294 | 2,812,328 | |||||||||||||||||||
| Other Asset Additions | 100,771 | 80,681 | 318,233 | 171,521 | ||||||||||||||||||||
| $ | 20,459,026 | $ | 8,567,226 | $ | 9,015,843 | $ | 44,560,502 | $ | 24,448,531 | |||||||||||||||
| Disposition of Property and Equipment | $ | - | $ | - | $ | (4,650,000) | $ | - | $ | (4,650,000) | ||||||||||||||
| Net Capital Additions | $ | 20,459,026 | $ | 8,567,226 | $ | 4,365,843 | $ | 44,560,502 | $ | 19,798,531 | ||||||||||||||
| Exploration & evaluation assets additions | $ | 2,461,506 | $ | - | $ | - | $ |
2,461,506 | $ | - | ||||||||||||||
Oil and Gas Reserves
The following tables summarize certain information contained in the independent reserves report prepared by AJM Deloitte as of December 31, 2013. 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").
Summary of Oil and Gas Reserves
(based on forecast price and costs)
| Reserves Category | Light and Medium Oil (Mbbl) |
Natural Gas Liquids (Mbbl) |
Natural Gas (MMcf) |
||||||||||||||||
| W.I. Gross |
Co.Share Gross |
Net | W.I. Gross |
Co.Share Gross |
Net | W.I. Gross |
Co.Share Gross |
Net | |||||||||||
| Proved Developed Producing | 988 | 993 | 820 | 711 | 754 | 539 | 12,095 | 13,209 | 11,130 | ||||||||||
| Proved Developed Non-Producing | 215 | 216 | 194 | 65 | 67 | 53 | 1,634 | 1,679 | 1,511 | ||||||||||
| Proved Undeveloped | 1,276 | 1,289 | 1,118 | 866 | 923 | 705 | 14,806 | 16,304 | 14,351 | ||||||||||
| Total Proved | 2,479 | 2,498 | 2,132 | 1,642 | 1,744 | 1,297 | 28,535 | 31,192 | 26,992 | ||||||||||
| Probable | 2,392 | 2,401 | 2,031 | 1,308 | 1,357 | 1,010 | 24,227 | 25,590 | 22,739 | ||||||||||
| Total Proved Plus Probable | 4,871 | 4,899 | 4,163 | 2,950 | 3,101 | 2,307 | 52,762 | 56,782 | 49,731 | ||||||||||
| Reserves Category | Total BOE as at December 31, 2013 (Mboe) |
Total BOE as at December 31, 2012 (Mboe) |
||||||||||||||||||
| W.I. Gross |
Co.Share Gross |
Net | W.I. Gross |
Co.Share Gross |
Net | |||||||||||||||
| Proved Developed Producing | 3,715 | 3,949 | 3,214 | 2,076 | 2,381 | 2,042 | ||||||||||||||
| Proved Developed Non-Producing | 552 | 563 | 499 | 433 | 443 | 386 | ||||||||||||||
| Proved Undeveloped | 4,610 | 4,929 | 4,215 | 4,039 | 4,338 | 3,765 | ||||||||||||||
| Total Proved | 8,877 | 9,441 | 7,928 | 6,548 | 7,163 | 6,193 | ||||||||||||||
| Probable | 7,738 | 8,023 | 6,831 | 5,058 | 5,356 | 4,473 | ||||||||||||||
| Total Proved Plus Probable | 16,615 | 17,464 | 14,759 | 11,606 | 12,518 | 10,667 | ||||||||||||||
| 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) | "Working Interest Gross" reserves are the Company's working interest (operating or non-operating) share before deducting royalty obligations and without including any royalty interests of the Company. |
| (4) | "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. |
| (5) | "Net" Reserves are the Company's working interest (operating or non-operating) share after deduction of royalty obligations plus 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, 2013(2) | As At December 31, 2012 (3) |
||||||||||||
| Reserves Category | 0.0% (M$) |
5.0% (M$) |
10.0% (M$) |
10% (M$) |
|||||||||
| Proved Developed Producing | 112,355 | 92,026 | 78,259 | 45,271 | |||||||||
| Proved Developed Non-Producing | 19,832 | 16,499 | 14,239 | 4,992 | |||||||||
| Proved Undeveloped | 105,640 | 75,062 | 54,859 | 49,387 | |||||||||
| Total Proved | 237,827 | 183,587 | 147,357 | 99,650 | |||||||||
| Probable | 257,412 | 156,838 | 103,791 | 67,357 | |||||||||
| Total Proved Plus Probable | 495,239 | 340,425 | 251,148 | 167,381 | |||||||||
| 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, 2013. |
| (3) | Forecast pricing used is based on AJM Deloitte published price forecasts effective December 31, 2012. |
| (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 2013, 2012 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)
| 2013 | 2012 | 2011 - 2013 | |||||||||
| Capital expenditures | 47.0 | 19.8 | 130.8 | ||||||||
| Change in future capital | 7.2 | 23.8 | 41.3 | ||||||||
| Total capital for F&D | 54.2 | 43.6 | 172.1 | ||||||||
| Reserve additions, net production (Mboe) | 3,083 | 2,409 | 8,005 | ||||||||
| Proved F&D costs - including future capital ($/boe) | 17.58 | 18.09 | 21.50 | ||||||||
| Proved F&D costs - excluding future capital ($/boe) | 15.25 | 8.22 | 15.85 | ||||||||
| Proved Recycle Ratio | |||||||||||
| Including future capital | 2.06 | 1.41 | |||||||||
| Excluding future capital | 2.37 | 3.10 | |||||||||
| Proved plus Probable Finding & Development Costs ($ millions) | |||||||||||
| 2013 | 2012 | 2011 - 2013 | |||||||||
| Capital expenditures | 47.0 | 19.8 | 130.8 | ||||||||
| Change in future capital | 33.9 | 35.7 | 78.3 | ||||||||
| Total capital for F&D | 80.9 | 55.5 | 209.1 | ||||||||
| Reserve additions, net production (Mboe) | 5,750 | 4,459 | 13,141 | ||||||||
| Proved plus Probable F&D costs - including future capital ($/boe) | 14.07 | 12.45 | 15.91 | ||||||||
| Proved plus Probable F&D costs - excluding future capital ($/boe) | 8.18 | 4.44 | 9.96 | ||||||||
| Proved plus Probable Recycle Ratio | |||||||||||
| Including future capital | 2.57 | 2.05 | |||||||||
| Excluding future capital | 4.42 | 5.74 | |||||||||
Net Asset Value ("NAV")
| As at December 31, 2013 ($ millions) | ||||||
| Present Value of Proved plus Probable Reserves, before tax (discounted at 10%) | $ | 251.1 | ||||
| Total Debt | (44.6) | |||||
| Net Asset Value | $ | 206.5 | ||||
| Common shares outstanding at year end | 147.1 | |||||
| Net asset value per share | $ | 1.40 |
| 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, 2013 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 2013 total debt, excludes non-cash items (MTM on commodity contracts and flow through share obligations). |
Advance Notice Bylaw
Yangarra is announcing that its Board of Directors approved the adoption of an advance notice by-law (the "Advance Notice By-law"). Among other things, the Advance Notice By-law fixes a deadline by which shareholders must submit a notice of director nominations to Yangarra prior to any annual or special meeting of shareholders where directors are to be elected and sets forth the information that a shareholder must include in the notice for it to be valid.
The Advance Notice By-law is similar to the advance notice requirements adopted by many other Canadian public companies. Specifically, the Advance Notice By-law requires advance notice to the Corporation in circumstances where nominations of persons for election as a director of Yangarra are made by shareholders other than pursuant to (i) a requisition of a meeting made pursuant to the provisions of the Business Corporations Act (Alberta) (the "Act"), or (ii) a shareholder proposal made in accordance with the provisions of the Act.
In the case of an annual meeting of shareholders, notice to the Corporation must be given not less than 30 or more than 65 days prior to the date of the annual meeting. In the event that the annual meeting is to be held on a date that is less than 50 days after the date on which the first public announcement of the date of the annual meeting was made, notice may be given not later than the close of business on the 10th day following such public announcement.
In the case of a special meeting of shareholders (which is not also an annual meeting), notice to the Corporation must be given not later than the close of business on the 15th day following the day on which the first public announcement of the date of the special meeting was made.
The Advance Notice By-law is effective immediately. At the next meeting of shareholders of the Corporation, shareholders will be asked to confirm and ratify the Advance Notice By-law. The full text of the Advance Notice By-law is available under Yangarra's profile at www.sedar.com.
Annual General Meeting of Shareholders
The Company's Annual General and Special Meeting of Shareholders is scheduled for 10:00 AM on Tuesday May 27, 2014 in the Tillyard Management Conference Centre, Main Floor, 715 5th Avenue SW, Calgary, AB.
Year End Disclosure
The Company's Annual Report (financial statements, notes to the financial statements and management's discussion and analysis) will be filed on SEDAR (www.sedar.com) and be available on the Company's website (www.yangarra.ca).
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 April 30, 2014.
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 Venture Exchange nor its Regulation Service Provider (as that term is defined in the Policies of the TSX Venture Exchange) accepts responsibility for the adequacy and accuracy of this release.
Image with caption: "1) Half cycle IRR is based on actual drilling and completion costs, production to date and P+P reserves. 2) Full cycle IRR allocates all other capital costs to the wells (i.e. land, G&G, infrastructure) (CNW Group/Yangarra Resources Ltd.)". Image available at: http://photos.newswire.ca/images/download/20140325_C6908_PHOTO_EN_38294.jpg
SOURCE: Yangarra Resources Ltd.
please contact James Evaskevich, President and CEO, at (403) 262-9558
CORPORATE PROFILE Yangarra Resources Ltd. is a junior oil and gas company engaged in the exploration, development and production of natural gas and oil with operations in Western Canada, with a main focus on Central Alberta, where the Company has extensive infrastructure...
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