Attached files
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| EX-32.1 - DAYBREAK OIL & GAS, INC. | i00248_ex32-1.htm |
| EX-23.2 - DAYBREAK OIL & GAS, INC. | i00248_ex23-2.htm |
| EX-23.1 - DAYBREAK OIL & GAS, INC. | i00248_ex23-1.htm |
| EX-31.1 - DAYBREAK OIL & GAS, INC. | i00248_ex31-1.htm |
| 10-K - DAYBREAK OIL & GAS, INC. | i00248_dbrm-10k.htm |
DAYBREAK OIL AND GAS, INC.
Southern San Joaquin Basin,
East Slopes Project
Kern County, California
Estimated Future Reserves
and Revenues
As of March 1, 2011
SEC Guideline Case
Table of Contents
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Reserve and Revenue Projections |
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Summary by Reserve Classification |
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One-Line Property Listing |
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Ranked by Class, State and County |
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Ranked by Discounted Value |
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Detailed Projections and Production Plots |
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Proved Developed Producing |
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Proved Developed Non-Producing |
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Proved Undeveloped |
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AUSTIN |
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HOUSTON |
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3345 Bee Cave Road |
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1001 McKinney |
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Suite 201 |
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Suite 420 |
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Austin, Texas 78746 USA |
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Houston, Texas 77002 USA |
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Tel 512.732.9812 |
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Tel 713.559.9950 |
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Fax 512.732.9816 |
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WWW.lonquist.com |
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Fax 713.559.9959 |
Mr.
James F. Westmoreland
President & CEO
Daybreak Oil and Gas, Inc.
601 West Main Ave., Suite 1012
Spokane, WA 99201
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Re: |
Daybreak
Oil and Gas, Inc. |
Dear Mr. Westmoreland:
Pursuant to your request, Lonquist & Co. LLC, (“L&Co”) has estimated the future oil and gas Reserves and projected the associated future revenues for certain properties owned by Daybreak Oil and Gas, Inc. (“Daybreak”). The properties evaluated herein are located in Kern County, California. At the request of Daybreak, we have evaluated Proved Developed Producing (“PDP”), Proved Developed Non-Producing (“PDNP”), and Proved Undeveloped (“PUD”) Reserves.
Effective March 1, 2011, our conclusions are as follows:
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Net to Daybreak Oil and Gas, Inc. |
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Proved Developed |
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Proved |
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Total |
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Total |
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Total |
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Grand |
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SEC Pricing as of March 1, 2011 |
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Producing |
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Non-Producinga |
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Estimated Future Net Oil/Condensate, bbl |
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80,500 |
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8,340 |
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148,990 |
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237,820 |
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0 |
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0 |
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237,820 |
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Estimated Future Net Gas, MMcf |
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0 |
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0 |
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0 |
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0 |
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0 |
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0 |
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0 |
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Total Future Gross Revenue, $ |
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6,139,410 |
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635,990 |
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11,363,320 |
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18,138,730 |
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0 |
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0 |
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18,138,730 |
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Estimated Future Production Taxes, $ |
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75,030 |
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7,780 |
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138,860 |
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221,650 |
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0 |
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0 |
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221,650 |
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Estimated Future Operating Expenses, $ |
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2,732,540 |
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221,120 |
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3,720,810 |
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6,674,480 |
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0 |
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0 |
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6,674,480 |
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Estimated Future Capital Costs, $ |
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0 |
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36,060 |
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1,631,250 |
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1,667,310 |
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0 |
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0 |
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1,667,310 |
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Estimated Future Net Revenue (“FNR”), $ |
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3,331,840 |
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371,040 |
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5,872,400 |
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9,575,290 |
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0 |
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0 |
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9,575,290 |
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Discounted FNR at 10%, $ |
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2,020,050 |
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258,910 |
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3,080,820 |
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5,359,780 |
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0 |
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0 |
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5,359,780 |
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Discounted FNR at 15%, $ |
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1,721,910 |
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223,360 |
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2,395,140 |
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4,340,420 |
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0 |
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0 |
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4,340,420 |
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Estimated Net Revenues by Year, $ |
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2011 |
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556,280 |
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50,930 |
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-666,280 |
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-59,070 |
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0 |
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0 |
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-59,070 |
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2012 |
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451,910 |
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75,780 |
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1,312,890 |
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1,840,590 |
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0 |
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0 |
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1,840,590 |
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2013 |
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331,220 |
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51,220 |
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827,100 |
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1,209,550 |
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0 |
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0 |
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1,209,550 |
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Subtotal |
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1,339,410 |
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177,930 |
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1,473,710 |
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2,991,070 |
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0 |
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2,991,070 |
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Thereafter |
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1,992,430 |
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193,110 |
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4,398,690 |
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6,584,220 |
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0 |
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6,584,220 |
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Total |
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3,331,840 |
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371,040 |
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5,872,400 |
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9,575,290 |
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0 |
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9,575,290 |
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Estimated Average Net Production Rate - 2011 |
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Oil/Condensate, bbl/D |
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30.0 |
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3.6 |
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42.7 |
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76 .3 |
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0 |
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76.3 |
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Gas, Mcf/D |
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0 |
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0 |
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0 |
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0 |
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0 |
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0 |
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aColumn includes the Proved Developed Non-Producing, behind pipe, and shut-in cash flows and volumes.
bTotals might not match due to computer rounding.
Daybreak Oil and Gas, Inc. –
March 1, 2011 Reserve Report
SEC 1P Reserve Report
April 19, 2011
Page 2 of 5
Purpose of Report and Standards of Practice
This report was prepared to provide the management of Daybreak Oil and Gas, Inc. with a projection of estimated remaining hydrocarbon Reserves and projected future net revenues, effective March 1, 2011. These estimates have not been adjusted for risk.
This report has been prepared in accordance with our understanding of the Securities and Exchange Commission, S-X Reg. §210.4-10a, dated December 30, 2008 (Modernization of Oil and Gas Reporting; Final Rule; January 14, 2009); we have evaluated the 1P Reserves. The applicable SEC oil and gas Reserve definitions are attached hereto.
Liquid hydrocarbon volumes are expressed in standard 42-gallon barrels. All natural gas volumes are sales gas expressed at the official pressure and temperature bases of the areas in which the gas Reserves are located.
All currencies in this report are expressed in U.S. dollars.
Reserve Estimates
Well-by-well production data in this report were updated through February 28, 2011. Extrapolation of historical production data was utilized for those producing properties where sufficient data were available to suggest decline trends. Reserves assigned to the remaining producing properties and the volumes associated with non-producing assets were determined by analogy to offset wells producing from similar formations or by volumetric analyses. Hydrocarbon volumes assigned by analogy and volumetric analyses are subject to greater revision than those projected using established performance trends.
As of March 1, 2011, the 1P net remaining Reserves were estimated to be 237,820 barrels of oil. The net present value, discounted at 10%, of the total Proved Reserves was $5,359,780. Of the total net revenue, discounted at 10%, 37.7% was derived from the PDP Reserves. The Reserve life index (“R/P”) of the PDP Reserves was estimated to be 7.4 years.
Property Overview
The San Joaquin East Slope Region, located in Kern County California, is operated by Daybreak Oil and Gas. On this leasehold, 3D seismic survey data have been shot on 22,000 acres. Using these data, twelve prospective areas have been identified, of which five have been drilled. The areas evaluated in this report, Sunday, Bear, Black, Dyer Creek and Ball have been classified as Proved, and are in the development phase. All production is from the Vedder formation, which is typically an unconsolidated reservoir requiring gravel packed completions.
Sunday Prospect
To date, the Sunday #1, #2, #3 and #4 have produced 50,920 barrels of oil from the Vedder formation. The Sunday #4 was drilled as a horizontal well but is producing as a vertical well after a workover. The Vedder net pay map over the Sunday Prospect contains 34.6 acres and three PUD locations were assigned.
Daybreak Oil and Gas, Inc. –
March 1, 2011 Reserve Report
SEC 1P Reserve Report
April 19, 2011
Page 3 of 5
Bear Prospect
To date, four wells have been drilled in the Bear Prospect. The Bear #1, #2, #3 and #4 are all producing from the Vedder formation. The Bear #3, the southernmost well in the pool, is believed to have mechanical problems and has never performed up to expectations. As a result of the mechanical issues, the Bear #3 has an estimated ultimate recovery of 2,818 barrels of oil. An offset location was not assigned in this area. At the time of this report, the identified pool covers 62 acres, of which 34 acres contain Proved Reserves. In addition, three PUD locations were identified.
Black Prospect
The Black Prospect is located south of the Bear Prospect, and contains 13.4 acres in the Vedder formation. The Black #1 is the only producing property in this area. After looking at core data and low productivity, a workover has been scheduled at the end of the current economic life to recover additional Reserves. At the time of this report, two PUD locations were identified.
Ball Prospect
The Ball Prospect is the northernmost pool in the Dyer Creek Field Trend and has 37.5 acres of mapped closure in the Vedder formation. The Ball #1-11 was drilled and completed in October 2010. A workover has been scheduled for May 2011 to repair a suspected leaking plug below the Upper Vedder. At the time of this report, two PUD locations were identified.
Dyer Creek Prospect
The Dyer Creek structure, which lies between the Bear and the Ball, is not closed to the south and therefore may be in communication with the Bear structure. The Dyer Creek #67X-11 was drilled and completed in October 2010. Due to completion problems, this well has an estimated ultimate recovery of 7,613 barrels of oil. At the time of this report, one PUD was identified.
Product Prices
The base oil price of $82.01 per barrel utilized herein is the average closing oil price of the first trading day of each month for the prior twelve months as of February 28, 2011, as reported by the Energy Information Administration. As stipulated by SEC regulations, no price escalations were included in this report. Product price differentials were calculated by comparing the realized prices, as calculated from revenue statements, to the average NYMEX futures price for the same calendar month. This average differential is expressed as a percentage multiplier on price in the economic model.
Daybreak Oil and Gas, Inc. –
March 1, 2011 Reserve Report
SEC 1P Reserve Report
April 19, 2011
Page 4 of 5
Operating Expenses
Direct operating expense data, input as dollars per month in the economic models, were supplied by Daybreak. These direct operating costs were based on actual expenses from March 2010 through February 2011, and were adjusted for non-recurring costs, where applicable.
Severance and ad valorem taxes were deducted as a percentage of gross revenues or as a charge per unit of production. The individual well projections of oil and gas cease when the operating expenses exceed the gross revenues.
Operating expenses were not escalated in this report.
Capital Expenses
Estimated capital costs were input as approximate costs for the operations that would be performed on wells in the PDNP and PUD Reserve categories. A more accurate cost estimate for these individual investments will be generated at the time they are carried out. These operations were modeled to start at a specific point in the future. Any deviation from these dates will result in a change in the projected future net revenues for those properties evaluated herein.
Capital expenditures were not escalated in this report.
Values Not Considered
In all cases we have attempted to account for all deductions from gross revenues except for the following:
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Federal Income Tax |
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Depreciation, depletion, and/or amortization, if any |
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Costs in excess of revenues from uneconomic leases |
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Plugging and abandonment costs in excess of salvage value |
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Environmental restoration costs, if any |
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Product price hedges, if any |
No value has been assigned to non-producing acreage or to acreage held by production.
Report Qualifications
The future net revenues were based on projections of recoverable hydrocarbons, rates of production, timing of recompletions and drilling, proration by state and federal agencies, direct taxes, and product prices. All estimated future net revenues presented in this report are after the deduction of royalties, production costs, and development costs. This evaluation does not include indirect costs such as administrative, overhead, and other miscellaneous expenses. Any unusual combination of the many factors, including weather, political risk or acts of terrorism could result in future receipts being considerably less or more than those estimated herein.
THE REVENUES AND PRESENT WORTH OF FUTURE NET REVENUES PRESENTED HEREIN ARE NOT REPRESENTED TO BE MARKET VALUES EITHER FOR THE INDIVIDUAL PROPERTIES OR ON A TOTAL PROPERTY BASIS.
Daybreak Oil and Gas, Inc. –
March 1, 2011 Reserve Report
SEC 1P Reserve Report
April 19, 2011
Page 5 of 5
Data Sources
Data including basic well information, geological interpretations, realized product prices, operating costs, initial test rates, and ownership interests were supplied by Daybreak. L&Co has accepted these data as correct.
Historical production data were obtained from Daybreak as well as public sources, such as Lasser Production Data Services, DrillingInfo.com, and HPDI Production Data Applications. Production data was updated though February 2011. We retain in our files digital databases for all properties and certain other hard copy information that we believe pertinent.
We have not inspected the properties evaluated in this report, nor have we conducted independent well tests.
Independent Evaluation
Neither Lonquist & Co. LLC nor any of its employees have any interest or ownership in the subject properties, and neither our employment nor compensation is contingent on our findings herein.
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Sincerely, |
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Lonquist & Co., LLC |
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Texas Registration No. F-8952 |
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/s/ RICHARD R. LONQUIST |
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Richard R. Lonquist, P.E. |
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Petroleum Engineer |
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Texas License No. 73008 |
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Date Signed: April 19, 2011 |
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Austin, Texas |
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/s/ TEREASA S. MONTEMAYOR |
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Tereasa S. Montemayor |
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Sr. Petroleum Engineer |
Daybreak Oil and Gas, Inc.
OIL AND GAS RESERVE DEFINITIONS
The Securities and Exchange Commission, SX Reg. § 210.4-10 dated November 18, 1981 as amended September 19, 1989 requires adherence to the following definitions of “Proved” oil and gas reserves:
Definitions:
(2) Proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
(3) Proved developed oil and gas reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
(4) Proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates, for proved undeveloped reserves be attributable to any acreage or which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Amended SEC guidelines Reg. § 210.4-10 definitions (Modernization of Oil and Gas Reporting; Final Rule; January 14, 2009):
(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10 percent probability that the total quantities ultimately recovered will equal or exceed the estimated proved plus probable plus possible reserves estimates.
(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by defined project.
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves, but which, together with proved reserves, are as likely as not to be recovered.
(i) When deterministic methods are used, that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus reserves. When probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the proved plus probable reserves estimates.
(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.