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Exhibit 99.1
This is a digital representation of a DeGolyer and MacNaughton report.
Each file contained herein is intended to be a manifestation of certain data in the subject report and as such is subject to the definitions, qualifications, explanations, conclusions, and other conditions thereof. The information and data contained in each file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information.
February 25, 2013
Lone Pine Resources Canada, Ltd.
1100, 640 - 5th Avenue SW
Calgary, Alberta T2P 3G4
Ladies and Gentlemen:
Pursuant to your request, we have prepared estimates of the extent and value of the net proved crude oil, condensate, natural gas liquids (NGL), and natural gas reserves, as of December 31, 2012, of certain properties owned by Lone Pine Resources Canada, Ltd. (Lone Pine). This evaluation was completed on February 25, 2012. The properties appraised consist of working interests in wells located in Alberta and British Columbia, Canada. Lone Pine has represented that these properties account for 100 percent of Lone Pine's net proved reserves as of December 31, 2012. The net proved reserves estimates prepared by us have been prepared in accordance with the reserves definitions of Rules 4—10(a) (1)—(32) of Regulation S-X of the United States Securities and Exchange Commission (SEC). This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by Lone Pine.
Reserves included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2012. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Lone Pine after deducting royalties and interests owned by others.
Data used in this evaluation were obtained from reviews with Lone Pine personnel, Lone Pine files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Lone Pine with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.
Methodology and Procedures
Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principals and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)." The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.
An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.
For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline
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curves, reserves were estimated only to the limits of economic production based on existing economic conditions. In certain cases, when the previously named methods could not be used, reserves were estimated by analogy with similar wells or reservoirs for which more complete data were available.
Gas volumes estimated herein are expressed as sales gas. Sales gas is defined as that portion of the gas volume to be delivered into a gas pipeline for sale after separation, processing, fuel use, and flare. Net gas reserves are reported as sales gas. Gas volumes are expressed at a temperature base of 60 degrees Fahrenheit (°F) and a pressure base of 14.65 pounds per square inch absolute (psia).
Crude oil volumes estimated herein are those to be recovered by normal field separation. Condensate and natural gas liquid (NGL) volumes reported herein are those to be recovered by passage through processing plant separation.
Definition of Reserves
Petroleum reserves estimated by us included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by us in this report are in accordance with the reserves definitions of Rules 4-10(a) (1)—(32) of Regulation S-X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:
Proved oil and gas reserves—Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible —from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
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(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Developed oil and gas reserves—Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
- (ii)
- Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Undeveloped oil and gas reserves—Undeveloped oil and gas reserves are reserves of any category 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.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4-10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.
The development status shown herein represents the status applicable on December 31, 2012. In the preparation of this study, data available from wells drilled on the appraised properties through December 31, 2012, were used in estimating gross ultimate recovery. When applicable, gross production estimated to December 31, 2012, was deducted from gross ultimate recovery to arrive at the estimates of gross reserves as of December 31, 2012.
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Our estimates of Lone Pine's net proved reserves attributable to the reviewed properties are based on the SEC definitions of proved reserves and are as follows, expressed in millions of cubic feet (MMcf) and thousands of barrels (Mbbl):
| | | | | | | | | | |
| | Estimated by DeGolyer and
MacNaughton | |
|---|
| | Net Proved Reserves
as of
December 31, 2012 | |
|---|
| | Oil and
Condensate
(Mbbl) | | NGL
(Mbbl) | | Natural
Gas
(MMcf) | |
|---|
Properties Reviewed by DeGolyer and MacNaughton | | | | | | | | | | |
Proved Producing | | | 6,601 | | | 168 | | | 75,715 | |
Proved Non-Producing | | | 55 | | | 8 | | | 1,346 | |
Proved Undeveloped | | | 11,613 | | | 0 | | | 772 | |
| | | | | | | | |
Total Proved | | | 18,269 | | | 176 | | | 77,833 | |
Primary Economic Assumptions
Revenue values in this report are expressed in terms of estimated future gross revenue, future net revenue, and present worth of future net revenue. These values are based on the economic conditions as defined by the SEC.
Future gross revenue is defined as that revenue to be realized from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated production taxes, ad valorem taxes, operating, gathering, processing expenses, and capital costs from the future gross revenue. Present worth of future net revenue is calculated by discounting the future net revenue at the arbitrary rate of 10 percent per year compounded monthly over the expected period of realization.
Revenue values in this report, expressed in Canadian dollars (CDN$) and United States dollars (U.S.$), were estimated using the initial prices and expenses provided by Lone Pine. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The prices used in this report are based on SEC guidelines. The assumptions used for estimating future prices and expenses are as follows:
Lone Pine has represented that the natural gas prices were based on a reference price, calculated 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, unless prices are defined by contractual arrangements. The gas prices were calculated for each property using differentials and heating value adjustments to the AECO reference price of CDN$2.37 per million British thermal units (MMBtu) and held constant thereafter. After adjustment for heating value, the volume-weighted average price was CDN$2.22 per thousand cubic feet.
Lone Pine has represented that the oil prices were based on a reference price, calculated 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, unless prices are defined by contractual arrangements. The prices were calculated for each property using differentials to an Edmonton Light reference price of CDN$87.90 per barrel and held constant thereafter. The volume-weighted average price was CDN$84.64 per barrel.
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The NGL prices were determined for each NGL product stream and based on a reference price, calculated 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, unless prices are defined by contractual arrangements. Prices were adjusted for gravity, quality, and transportation as provided by Lone Pine, and these prices were held constant thereafter. The volume-weighted average price was CDN$65.57 per barrel.
Operating expenses and capital costs, based on information provided by Lone Pine, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation. Abandonment costs were provided by Lone Pine and accepted as reasonable.
The estimated future revenue and expenditures attributable to the production and sale of Lone Pine's net proved reserves of the properties appraised, as of December 31, 2012, is summarized in thousands of Canadian dollars (M CDN$) as follows:
| | | | | | | | | | | | | |
| | Proved | |
|---|
| | Developed
Producing
(M CDN$) | | Developed
Nonproducing
(M CDN$) | | Undeveloped
(M CDN$) | | Total
Proved
(M CDN$) | |
|---|
Future Gross Revenue | | | 808,783 | | | 9,207 | | | 1,094,185 | | | 1,912,175 | |
Royalty Revenue | | | 851 | | | 49 | | | 0 | | | 900 | |
Royalties Deducted | | | 64,739 | | | 725 | | | 105,655 | | | 171,119 | |
Operating Expenses | | | 287,101 | | | 3,378 | | | 214,977 | | | 505,456 | |
Capital Costs | | | 8,061 | | | 1,907 | | | 379,998 | | | 389,966 | |
Abandonment Costs less Salvage Value | | | 14,776 | | | 176 | | | 4,574 | | | 19,526 | |
Future Net Revenue* | | | 434,957 | | | 3,070 | | | 388,981 | | | 827,008 | |
Present Worth at 10 Percent* | | | 258,700 | | | 1,550 | | | 113,348 | | | 373,598 | |
- *
- Future income taxes were not taken into account in the preparation of these estimates.
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Using an exchange rate of U.S.$1.010 per CDN$1.00, the estimated future revenue to be derived from the production and sale of the proved reserves, as of December 31, 2012, of the properties appraised, expressed in thousands of United States dollars (M U.S.$), is summarized as follows:
| | | | | | | | | | | | | |
| | Proved | |
|---|
| | Developed
Producing
(M U.S.$) | | Developed
Nonproducing
(M U.S.$) | | Undeveloped
(M U.S.$) | | Total
Proved
(M U.S.$) | |
|---|
Future Gross Revenue | | | 816,871 | | | 9,299 | | | 1,105,127 | | | 1,931,297 | |
Royalty Revenue | | | 860 | | | 49 | | | 0 | | | 909 | |
Royalties Deducted | | | 65,386 | | | 732 | | | 106,712 | | | 172,830 | |
Operating Expenses | | | 289,972 | | | 3,412 | | | 217,127 | | | 510,511 | |
Capital Costs | | | 8,142 | | | 1,926 | | | 383,798 | | | 393,866 | |
Abandonment Costs less Salvage Value | | | 14,924 | | | 178 | | | 4,620 | | | 19,721 | |
Future Net Revenue* | | | 439,307 | | | 3,101 | | | 392,871 | | | 835,278 | |
Present Worth at 10 Percent* | | | 261,287 | | | 1,566 | | | 114,481 | | | 377,334 | |
- *
- Future income taxes were not taken into account in the preparation of these estimates.
Estimates of oil, condensate, and gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.
While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant's ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2012, estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.
In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50,Extractive Industries—Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4—10(a) (1)—(32) of Regulation S-X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S-K of the Securities and Exchange Commission; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year.
To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.
DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Lone Pine. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the
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request of Lone Pine. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.
| | |
| | | Submitted, |
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DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716 |
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Paul J. Szatkowski, P.E.
Senior Vice President
DeGolyer and MacNaughton
|
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CERTIFICATE of QUALIFICATION
I, Paul J. Szatkowski, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:
- 1.
- That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Lone Pine dated February 25, 2013, and that I, as Senior Vice President, was responsible for the preparation of this report.
- 2.
- That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1974; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists; and that I have in excess of 38 years of experience in oil and gas reservoir studies and reserves evaluations.
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Paul J. Szatkowski, P.E.
Senior Vice President
DeGolyer and MacNaughton
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CERTIFICATE of QUALIFICATION
