EXHIBIT 99.1
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| P. +61 8 9420 6660 |
| F. +61 8 9420 6690 |
| 3/1138 Hay Street West Perth WA 6005 |
| PO BOX 275 West Perth WA 6872 |
| www.riscadvisory.com |
14 March 2014
Mr. Michael R. McElwrath
Far East Energy Corporation
333 N Sam Houston Pkwy E
Suite 230
Houston 77060 Texas
Dear Mr. McElwrath,
Shouyang US SEC Reserves as at 31 December 2013
At the request of Far East Energy Corporation, RISC has estimated the reserves and future revenue of the interests of Far East Energy Corporation and its wholly owned subsidiary (FEEC) in the coal bed methane property (CBM) located in the Shouyang Contract Area, China. The evaluation was completed on 14 March 2014.
The Shouyang Production Sharing Contract Area (PSC) with CUCBM, is in the Shanxi Province approximately 400 km south west of Beijing. The location map is shown in Figure 1. Development within the Shouyang Block is focused on the #3, #9 and #15 coal seams in the northern part of the PSC.
Figure 1 Shouyang Location Map
In November 2011, FEEC relinquished one portion labelled A2 in Figure 2 and agreed to permit CUCBM to proceed at its sole risk with a 100% participation interest. At the same date, Far East Energy is proceeding at its sole risk with 100% participating interest in the current production/gas sales area, Area A1, of 64.7 km2 (15,988 acres). FEEC relinquished a further area south-west of Area B on May 30 2013 , formerly called Area C. No reserves have been assigned to any relinquished areas. At end 2013, FEEC participates in and operates a total of 1167.8 km2 (288,569 acres). FEEC has a 100% interest in portion A1 and an interest in portion B of between 70% and 100% in partnership with CUCBM. The interest of FEEC depends on whether CUCBM elects to take up to a 30% participation interest within 30 days of receipt of notice of Chinese certification of CBM resources. FEEC's interest in Area B as of the date of this report is 100%, however the calculations in the report assume CUCBM will elect a 30% participation. In addition, ConocoPhillips has a 3.5 % Revenue Interest (RI) which has been deducted from the net reserves.
Figure 2 Shouyang Contract Area
The reserve estimates have been prepared in accordance with definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and the FASB Accounting Standards Codification Topic 932, Extractive Industries-Oil and Gas with the exclusion of future income tax and Chinese VAT. The SEC oil and gas reserve definitions are included at the end of this report. The purpose of the report is for FEEC’s use in filing with the SEC. RISC’s estimates of the gross and net reserves and net future revenue attributable to FEEC as at 31 December 2013 are shown in Table 1. Net reserves have been calculated from FEEC’s share of cost gas and profit gas in accordance with the PSC terms net of the ConocoPhillips revenue interest and account for 100% of FEEC’s proved petroleum reserves. The proved reserves set forth herein are attributable to approximately 32.9 km2 (8,132 acres) in Area A and 22.7 km2 (5,600 acres) in Area B. The proved plus probable reserves set forth herein are attributable to all of area A (64.7 km2 or 15,988 acres) plus approximately 281 km2 (69,440 acres) in Area B, inclusive of the proved locations.
| Gross Reserves | Net Reserves | Future Net Revenue $million |
| MMscf | MMscf | Undiscounted | 10% Discount |
| Category | | | | |
| Proved Developed | 14,985 | 13,993 | 83.2 | 51.2 |
| Proved Undeveloped | 60,043 | 53,507 | 260.4 | 116.2 |
| Total Proved | 75,028 | 67,501 | 343.5 | 167.3 |
| Probable Developed | 4,970 | 4,752 | 39.6 | 25.6 |
| Probable Undeveloped | 540,798 | 367,665 | 2,215.2 | 1,217.4 |
| Total Probable | 545,767 | 372,418 | 2,254.8 | 1,242.9 |
| Possible Developed | 4,706 | 4,499 | 37.7 | 20.3 |
| Possible Undeveloped | 164,820 | 104,880 | 835.6 | 542.9 |
| Total Possible | 169,526 | 109,378 | 873.3 | 563.1 |
Totals may differ due to rounding. Gas volumes are expressed in units of million standard cubic feet at reference conditions of 60 deg F and 14.696 psia Net Gas Reserves are net of CUCBM participating interest and COP revenue interest |
Table 1 Gross and Net Reserves and Future Net Revenue attributable to FEEC as at 31 December 2013
RISC did not evaluate the country and geopolitical risks in China and the provinces where FEEC operates or has interests. FEEC’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies, royalties, government subsidies or incentives, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.
Resource Evaluation
The resource evaluation is based on data from 142 CBM wells. In evaluating the resources, RISC has used generally accepted principles and methods as promulgated by the Society of Petroleum Engineers (SPE) in the Petroleum Resources Management System (PRMS)1 and Guidelines for Application of the Petroleum Resources Management System2 as well as in accordance with applicable definitions and regulations specified by the SEC.
1 Petroleum Resources Management System, prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE) and reviewed and jointly sponsored by the American Association of Petroleum Geologists (AAPG), World Petroleum Council (WPC), Society of Petroleum Evaluation Engineers (SPEE), Society of Exploration Geophysicists (SEG) and approved by the Board of the SPE in March 2007.
2 Guidelines for Application of the Petroleum Resources Management System, November 2011. Sponsored by the SPE, AAPG, WPC, SPEE, SEG and approved by the Board of the SPE in November 2011.
The data used in this evaluation included production performance, coal thickness, gas content measurements, gas storage capacity and proximate analysis data along with stratigraphic information from numerous coal exploration drill holes. Seismic data was limited to some regional lines that demonstrated the structural style and geological trends. The data indicate that the coal packages are quite continuous in the three target seams: #3, #9 and #15, with seam 15 (the deepest) being the most volumetrically significant. A number of smaller seams lie within these intervals that are currently not targeted for development. This represents a volumetric upside that has not been assessed or included in our estimates.
The target coal seams outcrop to the north of the block and can be examined in coal mines north of the Shouyang Block that are working the outcrop. The coal seams dip from north to south. Seam depths average from near surface to 900m below ground level in the north and have been demonstrated to contain commercial gas flow from as deep as 1380m in well SYS-05 in the south eastern portion of the block with prospectivity below this depth. The majority of the producing well and coal bore data is concentrated in the north of the Block, however as a result of recent drilling, there is now quite good coverage of a significant proportion of Area B and confidence in the accuracy of structure and coal seam isopach mapping has increased this area. The majority of CBM data has been acquired for the #15 seam and as a result there is less confidence in the regional distribution of CBM properties in the # 9 and # 3 seams. Reserves have been assigned to seam 15 in portions of area A and B and seam 9 in portions of area A where analysis of geoscience and engineering data provides a reasonable certainty that they are economically producible.
RISC has reviewed and accepts FEEC’s net coal thickness values for volumetric estimates. Within the proved and unproved reserves areas, the depth and thickness of coal was determined directly from observed well data. Within the areas to which proved and unproved reserves have been attributed, the average depth based on well data was used, however where a portion of the area was deeper than the deepest commercially producible coal seen in a well, the area was truncated at this limit and no proved or unproved reserves assigned beyond it. Within the proved areas, a low estimate of coal thickness determined from the well data was applied to direct offset locations. A best estimate of thickness was applied to offset locations in the probable case. In the possible case, a high estimate of thickness was applied to offset locations.
The seam thickness averages 4.0m for seam 15, 2.9m for seam 9 and 2.2m for seam 3. The production data also supports coal continuity over significant distances.
The desorbed gas content of the coals from the samples taken averages 14.7 m3/tonne as received (ar), but values as high as 25 m3/tonne have been observed in well SYS-05 in the south east of the permit. The average ar gas content does not vary significantly between seams, but there is a trend of increasing gas content and saturation with depth. Samples of ash content vary from 5% to 70% across each of the coal seams. For seam #15 and seam # 3 the ash content distributions are similar and the majority of samples have ash contents less than 20%. The coal density is typically 1.5 tonne/m3.
Data from well tests and performance analysis indicates coal permeability is in the range 10 to 300 millidarcies (mD) with an average permeability of approximately 50 mD. The critical desorption pressures based on production performance are in the range 90 to 490 pounds per square inch absolute (psia) with an average of approximately 250 psia.
As at 31 December 2013, there are 113 wells in Area A, including non-producing wells that are expected to be placed on production after (re-)fraccing in 2014. There are 39 wells in Area B, although reserves are only attributed to 6 of these at the effective date of this report (31 December 2013) as dewatering is in progress and the wells have yet to demonstrate economic gas production. Since the effective date of this report, several wells in Area B have demonstrated economic production and subject to performance, it is anticipated that reserves will be attributed to additional Area B wells in future reviews. Dewatering
commenced in 2005 and 1.75 billion standard cubic feet (Bcf) of gas has been produced to 31 December 2013.
FEEC has evaluated various completion technologies including cavitation and fracture stimulation (water frac, resin-coated sand frac, nitrogen frac, gel frac and foam frac). They have selected fracture stimulation as the preferred technique. The well performance to date reflects the use of a number of completion techniques that have been determined as a result of the pilot studies to be sub optimal. In 2013, wells were drilled and fracced with more modern rigs, techniques and larger sand size pumped into the fracture stimulation. This process has led to increased gas rates in wells drilled in the latter part of 2013 and consequently the average production performance can be expected to improve for future development wells.
Well spacing employed by FEEC varies from approximately 30 to 140 acres, with most wells in the most intensely developed 1H production area drilled on an approximate 30-40 acre spacing. Analysis of the reservoir pressure and geological data between producing wells has shown that an average well drainage area of 80 acres is reasonably certain. In order to accelerate the dewatering of the coals, a 40 acre infill development well spacing is planned by FEEC.
Technologies Used to Determine Proved Reserve Estimate
A variety of technologies were used to estimate the proved reserves. The principal methodologies employed are decline curve analysis, numerical and analytical material balance models that have been historically matched to producing wells, analysis of coal thickness, density and depth from drilling and wire line log evaluation, echometer and down hole pressure sensors to estimate the reservoir pressure from water levels in pumping wells, gas content measurements from desorption and adsorption tests performed on core samples of coal taken from wells drilled in the field, permeability estimates from transient well test analysis carried out on wells drilled in the field and analogue performance from wells within the field. Seismic data use was limited to identifying structural trends and regional dips, but was not used to predict the presence, continuity or thickness of the reservoir.
Development Plan
To fulfil the requirements of the PSC, FEEC has advised they are obliged to drill Exploration/Appraisal wells (called 'Parameter wells') in order to retain development rights in the block. A total of 13 Parameter wells are planned for 2014 under the PSC commitments. No production or reserves have been attributed to these wells, however the costs for these wells have been included in the economics.
FEEC has advised a firm development drilling program of up to 2126 development wells planned with 25 rigs in areas A and B for the years 2014 to 2018 from which the current estimates of reserves in this report are based. 256 development wells plus 13 commitment Parameter wells are planned for 2014 with 600 wells per year in 2015, 2016, 2017 and 70 wells in 2018. For the proved undeveloped reserves case, a total of 295 development well locations have been identified in areas A and B (Table 3). For the probable and possible undeveloped reserve cases, an additional 1831 development well locations have been identified. Future drilling is based on a well spacing of 40 acres to accelerate the dewatering process. FEEC has advised that there are virtually no areas within the PSC that are inaccessible for CBM development, as deviated wells will be used to access coal seams located below areas with restricted surface access.
RISC recommends that Far East considers the use of “shield wells” to accelerate dewatering within a pattern, possibly using horizontal completions which if successful would improve production and economics.
Development Area | Producing and Non Producing Wells included in development | Future Development Wells (excluding 13 Parameter wells in Area B) |
| | Proved | Probable and Possible | Total Proved + Probable + Possible |
| A | 113 | 161 | 161 | 322 |
| B | 6 | 134 | 1670 | 1804 |
| Total | 119 | 295 | 1831 | 2126 |
Table 2 Shouyang Block Development Proved and Probable Undeveloped Areas and Development Well Count
RISC has assumed future development wells are fracture stimulated. The initial development is focussed on seam 15. In 2014, 32 wells located in the portion of seam 9 within area A where reserves have been established are assumed to be fracture stimulated and produced comingled with seam 15.
Gas production forecasts used were generated using industry-standard industry numerical modelling software for coal bed methane. Each development area and coal seam were modelled separately, based on parameters from the geological analysis, laboratory data and determined from analysis of production.
Production forecasts were truncated at the end of the PSC term at 30 June 2032 unless production becomes uneconomic before that date.
The gas composition typically has 96% methane with low CO2 and N2 content, consequently the gas does not require conditioning to meet pipeline specifications.
After drilling and completion, wells will be hooked up to a simple gas gathering system. Water is separated at the well site and disposed of by evaporation. Gas is transported to localised gas plants consisting of a simple dehydration and compression up to 500 psi for delivery to a third party gas network. The field is operated using electricity purchased from a local grid. On this basis it was assumed that all new pilot production areas in the future start with only 60% of production sold as sales gas, rising to 100% after one year.
Capital and operating costs were supplied by FEEC. These are summarised in Appendix 1 and have been used for the proved reserves case. For the probable and possible cases, the same cost base was used; however, we have estimated a drilling learning curve commencing in 2015 resulting in a 10% improvement in well costs over 2 years.
Economics
RISC has estimated undiscounted and discounted future net revenue using the fiscal and working interest terms defined in the Shouyang Block PSC supplied by FEEC and the Fifth Modification Agreement dated 11 November 2011 (English versions). The economic assumptions are:
| | § | FEEC has a 100% interest in PSC area A1 and a 70% interest in area B where it is assumed that CUCBM will elect to take up its full 30% participating interest upon Chinese certification of CBM resources. The assumption for the purposes of this report is that CUCBM made such an election on 31 December 2012; |
| | § | The PSC term expires on 30 June 2032; |
| | § | Government royalty of 0-3% based on production levels; |
| | § | Cost Recovery Limit 75%; |
| | § | The evaluation date is at 31 December 2013; |
| | § | The gas price used is US$8.89/Mscf3 (thousand standard cubic foot) in accordance with the gas contract sales price advised by FEEC and Chinese Government subsidies. The US dollar price is based on the contract price received, relevant subsidies and the average of the US dollar-Yuan exchange rate on the first day of each month in 2013; |
| | § | The gas sales agreement has a 20 year term expiring on 10 June 2030. RISC has assessed that gas sales beyond the current contract term are reasonably certain and consequently has assigned reserves until the end of the PSC term; |
| | § | No cost or price inflation has been applied; |
| | § | A 10% nominal mid-year discount has been used as the rate for the discounted future net cash flow; |
| | § | RISC has used a past cost balance of US$187.5 million exploration (100% FEEC) and a $2.84 million balance due to CUCBM for past exploration at 31/12/2013, as supplied by FEEC. We have not audited these costs; |
| | § | A revenue interest of 5% of FEEC's participating interest, capped at 3.5% for FEEC's participating interest greater than 70%4 is payable to ConocoPhillips; |
| | § | The future cash flows are defined as FEEC’s share of cost gas and profit gas in accordance with the PSC terms less royalties. Future cash flows are before income tax and Chinese VAT. |
The economic values contained in this report are for the purposes of demonstrating economic viability to meet standard cash flow measures under Regulation S-X. They do not purport to be the fair market value of FEEC’s interests in the Shouyang Block.
Qualifications
RISC is independent with respect to FEEC as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. RISC has no pecuniary interest, other than to the extent of the professional fees receivable for the preparation of this report, or other interest in the assets evaluated, that could reasonably be regarded as affecting our ability to give an unbiased view of these assets.
The assessment of petroleum assets is subject to uncertainty because it involves judgments on many variables that cannot be precisely assessed, including reserves, future oil and gas production rates, the costs associated with producing these volumes, access to product markets, product prices and the potential impact of fiscal or regulatory changes.
The statements and opinions attributable to RISC are given in good faith and in the belief that such statements are neither false nor misleading. In carrying out its tasks, RISC has considered and relied upon information obtained from FEEC as well as information in the public domain. The information included well reports, seismic data, maps, interpretation reports, production and well completion data, AFE’s, previous analyses, financial records and legal documents. The material was reviewed for its quality, accuracy and validity and was considered to be acceptable. RISC believes that that full disclosure has been made of all relevant material in FEEC’s possession and that information provided, is to the best of its knowledge, accurate and true.
The information provided to RISC has included both hard copy and electronic information supplemented with discussions between RISC and representatives of FEEC.
Whilst every effort has been made to verify data and resolve apparent inconsistencies, we believe our review and conclusions are sound, but neither RISC nor its servants accept any liability, except any liability which cannot be excluded by law, for its accuracy, nor do we warrant that our enquiries have revealed all
3 Under the gas sales agreement, the sales volume is defined at conditions of 20 deg C and 1.01325 bars absolute. The reserves and production in this report are stated at conditions of 60 deg F and 14.696 psia. Therefore a correction factor of 1.0154 has been applied to the gas volumes in the economic model to adjust for the different reference conditions. The gas price is net of a local sales tax of USD0.08/Mscf advised by FEEC.
4 As advised by FEEC
of the matters which an extensive examination may disclose. In particular, we have not independently verified property title, encumbrances, regulations and future costs that apply to these assets. RISC relied on FEEC’s advice in relation to opening balances at the evaluation date of past recovered and unrecovered development and exploration costs.
RISC has not made a physical inspection of the property as this was not considered necessary for our assessment.
Our assessment was carried out only for the purpose referred to above and may not have relevance in other contexts. The estimates contained in our assessment may increase or decrease and RISC’s opinions may change as further information becomes available.
The evaluation has been carried out by RISC staff under the supervision of Mr Geoffrey J Barker. Mr Barker has a B.Sc. from Melbourne University and a M.Eng. (Pet. Eng) from Sydney University. He has over 30 years experience in the oil and gas industry, has been a partner of RISC since 1996, is the Partner in charge of RISC’s unconventional gas practice and served on the SPE’s Oil and Gas Reserves Committee from 2006-2009. He has been responsible for company and property valuations, independent expert reports, reservoir studies, reserve assessments, business and project development plans for oil and gas properties in more than 50 countries.
This report was completed on 14 March 2014.
Yours sincerely,
Geoffrey J Barker
Partner
Definitions of Oil and Gas Reserves
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a).
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties
(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:
(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii) Same environment of deposition;
(iii) Similar geological structure; and
(iv) Same drive mechanism.
Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.
(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.
(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
(6) 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.
(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
| | (i) | Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves. |
| | (ii) | Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead |
| | (iii) | Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. |
| | (iv) | Provide improved recovery systems |
(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
| | (i) | Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs. |
| | (ii) | Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records. |
| | (iii) | Dry hole contributions and bottom hole contributions. |
| | (iv) | Costs of drilling and equipping exploratory wells. |
| | (v) | Costs of drilling exploratory-type stratigraphic test wells |
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.
(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
(16) Oil and gas producing activities.
(i) Oil and gas producing activities include:
(A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;
(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
(1) Lifting the oil and gas to the surface; and
(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:
a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.
(ii) Oil and gas producing activities do not include:
(A) Transporting, refining, or marketing oil and gas;
(B) Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
(D) Production of geothermal steam.
(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% probability that the total quantities ultimately recovered will equal or exceed the 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 a defined project.
(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
(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, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities 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.
(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
(20) Production costs.
| | (i) | Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: |
| | (A) | Costs of labor to operate the wells and related equipment and facilities. |
| | (B) | Repairs and maintenance. |
| | (C) | Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. |
| | (D) | Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. |
| | (ii) | Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above. |
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
(22) 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.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(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.
(23) Proved properties. Properties with proved reserves.
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs
(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
(31) 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 paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
(32) Unproved properties. Properties with no proved reserves.
APPENDIX 1 – SUMMARY OF CAPEX AND OPEX
CAPEX Items |
| Wells | Amount | Unit |
| - Well Drill & Complete (Multi-zone) | 425 | $’000/well |
| - Well Drill & Complete (900 m deviated) | 350 | $’000/well |
| - Well Drill & Complete (1200m parameter) | 500 | $’000/well |
| - Well Frac | 50 | $’000/well |
| - Well Recompletion (to upper zones) | 50 | $’000/well |
| Gathering & Hook-up | | |
| - Gathering & Hook-up | 25.6 | $’000/well |
| Gas Plant | | |
| - Gas (TEG) Plant | 87.1 | $’000/MMscfd |
| - Compression | 233.7 | $’000/MMscfd |
OPEX Items |
| Wells | | |
| - Well Opex | 1,500 | $/well/month |
| Facilities | | |
| - Electricity | 0.35 | $/Mcf of gas sold |
| - Variable | 0.154 | $/Mcf of gas sold |
| - Maintenance | 10.25 | $'000/MMscfd/year |
| - Staff | 25.6 | $'000/person/year |
