1 P a g e. Annual Statement of Reserves 2011

Transcription

1 1 P a g e Annual Statement of Reserves 2011

2 Index CEO Introduction and Disclaimer. 3 Summary 4 Assumptions and Methodology. 5-6 Year to Year Changes 7 Consolidated Results.. 8 Management Discussion and Analysis P a g e

3 CEO Introduction The 2011 Reserve Report articulates the Company s 1P, 2P and 3P reserve position as certified by its long-standing reserve and resources third party certification agent, Schlumberger Technology Corporation ( Schlumberger ). Schlumberger s report is entitled Reserve and Economic Evaluation of Proved, Probable, Possible Reserves and Contingent Resources Of Certain Norse Energy Corp. USA Oil & Properties as of 31 December The Company has adopted a policy of regional Reserve Reporting using external third party companies to audit its work and certify reserves and resources according to the guidelines established by the Oslo Stock Exchange (OSE). Reserve and Contingent Resource estimates comply with the definitions set by the Petroleum Resources Management System (PRMS) issued by the Society of Petroleum Engineers (SPE), the American Association of Petroleum Geologists (AAPG), the World Petroleum Council (WPC) and the Society of Petroleum Evaluation Engineers (SPEE) in March Disclaimer The 2011 Reserve Report for Norse Energy Corp. ASA should be reviewed with the following conditions in mind: There are numerous uncertainties inherent in estimating hydrocarbon reserves and resources, and in projecting future production volumes, costs and cash flows: o Reservoir assessments in general must be recognized as subjective processes of estimating hydrocarbon volumes that cannot be measured in an exact way o Assessments made by others may vary materially o The accuracy of any assessment is a function of the quality of available data and of engineering and geological interpretations o Results of future drilling, testing, production and new technology applications may justify revisions that could be material o Reserve and resource estimates are often different from the quantities of hydrocarbons that are ultimately recovered as are actual timing and costs related to the recovered volumes compared to the assumptions. The reported results reflect independent third party reviews of available technical and economic data sets and assumptions available by the end of Interpretations and assumptions made may change over time which again may affect the reported results. The company uses third party certifications as a supplement to its decision process. In -house evaluations are also considered. Houston, 30 April 2012 Mark Dice Chief Executive Officer 3 P a g e

4 Summary The Company s 1P, 2P and 3P Reserves for 2011 are summarized in the table below: Norse segment 1P reserves () 2P reserves () 3P reserves () USA Norse s P Reserves as of 31 December 2011 increased from 6.12 to 7.72 compared to 31 December 2010, an increase of ~26%. 2P Reserves as of 31 December 2011 increased from 7.30 to compared to 31 December 2010, an increase of ~47%. 3P Reserves as of 31 December 2011 increased from 7.89 to compared to 31 December 2010, an increase of ~37%. All of the Company s Reserves are located in its Central New York asset. The Company s 2C Contingent Resources also increased from 2010: 2C Contingent Resources as of 31 December 2011 increased from 697 to 880 compared to 31 December 2010, an increase of ~26%. Western New York 2C Contingent Resources, newly certified, total 164 and comprises gas (116 ) and oil (48 MMBO). Central New York 2C Contingent Resources increased from 697 to 715, an increase of ~3%, inclusive of 12/31/2011 divestiture. 4 P a g e

5 Assumptions and Methodology The Company uses the Appalachian Basin-wide standard of time-rate curve analysis for reserve quantification. This methodology is acceptable due to the long productive life for most Appalachian assets and is a prudent and accurate method that is acceptable for the SPE standard method of reporting. The basic building block for reserve quantification is reservoir depletion, frequently defined as reaching the economic break-even hurdle driven by permeability and reservoir quality. This infers that appreciable gas volumes remain un-recovered absent improvements in economic efficiency and technology. Most properties, therefore, reach economic limits prior to true depletion. Well performance is modeled on a well history basis for all developed assets. A best-fit time-rate curve is extrapolated based on historical performance to give the best overall expected view of future performance characteristics for individual properties. At year-end 2011, the Company managed 100 wells in this category. Appropriate working interest and net revenue interest positions are built into each well forecast. Subsequently, operating expenses, gathering and shrinkage expenses, and capital requirements are netted against the performance forecast until either reaching the well economic limit or reaching the 40 year forecast terminus whichever comes first. For as yet undeveloped assets where sufficient production histories from nearby properties exist, type curves generated based on localized averaging of those producing properties is used as the basis for gross production. For formations with limited production history, testing and reservoir modeling are used as additional support for type curve development. The same expense dynamics noted earlier, which are based on company accounting documentation of operating expenses and capital requirements, form the basis for assigning reserves on an individual prospect basis. The undeveloped position of the company involves assets in all categories accepted by SPE definitions. They are qualified as Proved, Probable, and Possible. These traditional deterministic reserve calculations are geologically defined, based on assessed drilling risk following conventions accepted in Appalachian reserve analysis, and followed by the company s US reserve analysts. The Company s large volume of well log and interpretive drilling data complements thorough understanding of the producing horizons especially when considering the extensive drilling density in the area of the company s operations. The first step in the process is to generate base maps. The second step is to identify drilling locations aided by 3D seismic interpretation and desired prospect features. The third step is a review by the Company s certified reserve analysts (Schlumberger) to validate and categorize the drill prospects into either proved undeveloped locations, probable locations, or possible locations. Schlumberger is very conservative in their approach and their categorizations meet the SPE definitions previously described. In addition to 1P, 2P, and 3P reserves, the Company s technical staff have identified, and its reserve certification agents have certified, 2C Contingent resources in both its Central New York and Western New York lease areas. Maps were prepared for all reservoir layers using extensive 2D and 3D seismic data followed by the placement of development pads, and then the assignment of a number of drilling locations for each pad. This was done for both Central and Western New York areas. Quantification of the Contingent Resource potential is consistent with the same deterministic reserve calculation methodology used to identify 1P, 2P, and 3P reserves. These contingent resources are identified by integrating the 3D seismic with other geological, petrophysical and engineering data. Contingent resources are typically located too distant from established production targets to sufficiently mitigate drilling and economic risks, which would allow their inclusion in higher reserve categories. In addition to the technical assumptions and methodology, there are also certain US pricing assumptions used by Schlumberger in the economic determination of reserves. 5 P a g e

6 Pricing For purposes of reserve report generation, the Company uses year-end pricing forecasts as of the last trading day of the calendar year (New York Mercantile Exchange NYMEX ) coupled with contractual hedges the Company has in place as risk mitigation measures. When calculating reserves, the Company s methodology includes the use of hedged gas pricing for all applicable gas volumes. This is consistent with SEC requirements in place in the US. Contract Time Frame Contract Volume (MMBtu) Contract Price (USD/MMBtu) Contract #1 Through 3 / ,000 / Month USD Contract #2 Through 12 / 2013 Varies 0 to 59,744 / Month USD Contract #3 Through 12 / 2015 Varies 25,000 to 50,000 / Month USD to For any additional scheduled production volumes exceeding contracted (hedged) volumes, the Company uses an annually weighted NYMEX strip price for the five trailing years based on the last trading day on the exchange for the prior year. For the current report, the last trading day for the NYMEX was December 31, In addition, an Appalachian pricing adjustment of USD per MMBTU is applied to the spot pricing settled averages to adjust the report for local market conditions (which historically trades positive to the market). This again is consistent with SEC requirements for reserve reporting in the United States. As Appalachian reserves are long lived, acceptable reserve reports include 40-year default well life absent any economic considerations, which require reserve calculation termination prior to that time. Consequently, for time periods exceeding the 5 year strip price coverage, that last price is used as the base price for any remaining economic calculations required by the reserve report. The 5-year average strip prices (USD/MMBtu) used in the current report follows, when adjusted for Appalachian market premium: P a g e

7 Year (2011) to Year (2010) Changes Annual Statement of Reserves 2011 As documented earlier, the following table is the Company s 1P, 2P and 3P reserve position at the end of Norse segment 1P reserves () 2P reserves () 3P reserves () USA Norse s During 2011, the Company had the following reserves development: Reserves Development 2P reserves () Balance (previous ASR) as of December 31, Production Acquisitions/disposals since previous ASR - Extensions and discoveries since previous ASR - New developments since previous ASR 3.99 Revisions of previous estimates Balance (current ASR) as December 31, Notes: o Figures are consolidated on a corporate level o Reserve and resources estimates comply with the definitions set by the 2007 SPE Reserves and Resources Management System (PRMS) The most significant changes compared to last year s report are mainly attributable to: The drilling and completion of seven new Herkimer horizontal wells, whose production during the course of the year served to offset the natural decline of the overall Herkimer reservoir performance price decline The addition of 24 new proved undeveloped locations The addition of 24 new probable drilling locations All US numbers from Schlumberger are net to the company s interest after royalties 7 P a g e

8 Consolidated Results 2011 Annual Statement of Reserves Developed Assets As of Dec. 31, P/P90 2P/P50 Norse Energy Central New York % % Under Development Assets As of Dec. 31, P/P90 2P/P50 Norse Energy Central New York % % Non-Development Assets As of Dec. 31, P/P90 2P/P50 Norse Energy Central New York % % assets P a g e

9 Management Discussion and Analysis US Annual Statement of Reserves 2011 In 2011, the Company continued its development of the Herkimer field with the intention to drill 30 wells from its 3D prospect portfolio under certain assumptions of well costs, well recovery, and gas prices. The campaign started in late 2010, at which time spot gas prices were averaging USD 4.00 per Mcf. Early results were encouraging with well recoveries and initial production rates coming in as prognosed. However, as the campaign progressed, well costs were significantly higher than planned, and well rates were variable across the field. In addition, gas prices continued to fall, and the SGEIS continued to be delayed. The performance of the drilling contractor was less than expected. Given all of the above, the Company decided to suspend its Herkimer drilling campaign after eight wells had been drilled, and focus its corporate resources on the planning, permitting and development of its Marcellus and Utica shale resources in Central New York, and identification of lower cost Herkimer drilling options. While the shift to shale started, the Company continued to build its inventory of high quality Herkimer drilling locations defined by 3D seismic in its Central New York asset, leading to a quality portfolio of 119 drilling locations. Schlumberger, as part of its year-end 2011 reserve certification process, categorized 78 of those locations as proved undeveloped, 40 as probable, and 1 as possible (60.7 net bcf 3P). These advances in the technical development work of the Herkimer reservoir provided the basis for the significant 2P and 3P reserve increases at the end of Central New York (Herkimer and shale permitting) was the Company s primary strategic focus in Fourteen shale permits are in the queue at the New York DEC awaiting final passage of the SGEIS regulations, and more are in preparation. The Company continues to seek strategic partners to develop its Marcellus and Utica gas resources in Central New York. An additional focus started to emerge at the end of 2011 in Western New York. The Company performed work in the fourth quarter of 2011 to assess the liquids potential in the Devonian (Rhinestreet, Middlesex, Geneseo, Skaneateles, Marcellus), and Utica shales. Schlumberger then independently, as part of their 31 December 2011 Reserve and Resource Certification work, confirmed that there is oil potential in the Devonian shale of 48.3 net MMBO, and gas potential in the Utica shale of 0.65 net Tcf. The certification of new oil resource, and growth of new gas resource, in the Company s Western New York acreage enhances the Company s portfolio product mix, strengthens its ability to manage the impacts of recently depressed gas prices, and provides exposure to relatively higher oil prices. Preliminary development plans are looking attractive. Further technical work, including third party assurance of all assumptions, is ongoing this will ensure that lessons learned from the Herkimer campaign are integrated into the Western New York development plan. The Company s Certified Contingent 2C oil and gas resource in New York increased to 4.9 TCFGE (880 ) compared to 3.9 TCFG (697 ) at the end of 2010 despite the year-end divestiture. Of the Central New York 2C volumes of 3.9 net TCFG, the Utica accounts for 2.6 net TCFG and the Marcellus 1.2 net TCFG; the Utica contains roughly twice as much 2C as the Marcellus. The Company s Certified Contingent 2C Resources as of 31 December 2011 now include 164 in Western New York of which 48 MMBLS is oil. The Company s newly added certified contingent resources in Western New York include both oil and gas resources. 9 P a g e

10 DEFINITIONS: Proved Reserves Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods and government regulations. Probable Reserves Probable Reserves are those additional Reserves which analysis of geoscience and engineering date indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. Possible Reserves Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves. 1P = Proved Reserves 2P = Proved and Probable Reserves 3P = Proved, Probable and Possible Reserves Contingent Resources Those quantities of petroleum estimated as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered commercially recoverable due to one more constraints. 10 P a g e