EX-99.1 10 ex99-1.htm EXHIBIT 99.1 ex99-1.htm
EXHIBIT 99.1
 
Gleason Engineering
4621 South Cooper; Suite 131-343
Arlington, Texas 76001
(817) 472-8017

March 01, 2013

Ms Kristi Humphries
HKN Bakken, Inc.
160 State Street
Suite 200
Southlake, Texas 76092
 
Re: Wattenberg (Codell-Niobrara);
Tobacco Garden North (Bakken);
Brooklyn (Bakken); Epping (Bakken)
Field Properties
Weld County, Colorado;
McKenzie & Williams County, North Dakota;
 
Gentlemen:

At your request, Gleason Engineering has prepared an estimate of proved hydrocarbon liquid and gas reserves, and future production rates as of January 1, 2013, to the interests of HKN Bakken, Inc., attributable to certain producing wells, which are currently producing in the field areas referenced above. Specific financial data for revenue, expenses and production were used to form the basis of this analysis. In the case where specific data were not available, generalized parameters were utilized. The resulting valuations and conclusions in this report are best estimates based on current understanding, but are not guaranteed to be exact given the inherent uncertainties in forecasting reserves, prices, expenses and operating conditions.

The summary table below presents the estimated net remaining Proved Producing reserves as of January 1, 2013 reviewed by Gleason Engineering. Hydrocarbon liquid volumes are expressed in standard 42 gallon barrels and are comprised of crude oil, condensate and natural gas liquids. All sales gas volumes are expressed in thousands of cubic feet (MCF) at the official temperature and pressure bases of the areas where the gas reserves are located.

Estimated Gross and Net Remaining Reserves
Attributable to the Interests of
HKN Bakken, Inc.
As of January 1, 2013
 
Reserve
Category
 
 
Gross Oil
Volumes
 
(bbl)
Gross Gas
Volumes
 
(mcf)
Net Oil
Volumes
 
(bbl)
Net Gas
Volumes
 
(mcf)
Future
Net Cash
Flow
 
( $ )
PV @
10%
 
( $ )
             
Proved
Producing
1,553,295
2,812,054
17,173
28,668
1,271,727
834,865
             
Total Proved
1,553,295
2,812,054
17,173
28,668
1,271,727
834,865

 
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Gleason Engineering
 

Review Procedure and Opinion

For the wells reviewed by Gleason Engineering, estimates of future reserves were prepared in accordance with standard engineering practices accepted by the petroleum industry and by petroleum engineering and geoscience professional societies.

In performing our review, we relied upon data available from the commercial databases of IHS Energy Group, the public database of the various state agencies which regulate oil and gas activities in the respective jurisdictions. HKN Bakken, Inc., provided certain information related to the ownership interest for each well evaluated. HKN Bakken, Inc., also provided a historical record of revenue and expenses for each well evaluated. This was necessary so Gleason could conduct such tests and reviews necessary to adequately evaluate the ongoing operations of each property. Gleason Engineering relied on its experience and expertise to estimate data necessary for this analysis but not available from public domain or commercial sources or directly from HKN Bakken, Inc.

Future Production Rates

Twelve (12) producing wells were evaluated in this analysis. Two (2) of the wells are indicated by records search to be dually completed, though only one completion interval in each well is active. Future production is forecasted using the industry-standard method of decline curve analysis, which predicts future production from the trend established by a well's past production history.

Product Pricing

The client provided specific pricing information for each well in the Lease Operating Statement submitted for review. Historical postings of 'first of the month average' oil prices and gas prices were used to establish the variance between reported prices received and the regional postings for the commodities. For forecasting purposes, gas pricing was based on the Henry Hub price settled effective December 31, 2012. Oil pricing was based on the average posted price for each producing region reported adjusted against the West Texas Intermediate Posted Oil Price.

Historical analysis of prices received to Henry Hub gas indicated that the actual gas price in Colorado averaged $0.22/mcf differential and oil prices received averaged $10.66/bbl differential to WTI. In North Dakota the gas price differential to Henry Hub is $3.55/mcf and the oil price differential to WTI is $6.02/bbl. The base prices for oil and gas used for forecasting purposes in this report are, $95.05/bbl and $2.75/mcf.

Operating Costs

Expenses used in this analysis were based on information supplied by HKN Bakken, Inc., in the form of a Lease Operating Expense Summary for each well. The gross costs were evaluated and judged to be consistent with operating conditions familiar to Gleason in the area. These actual costs, averaged over the past calendar year, were used in the economic forecast.

Reserve Estimates

The reserves for the wells reviewed by Gleason Engineering were estimated utilizing generally accepted engineering practices. An analysis and interpretation of production history was utilized to make the estimate of recoverable reserves from the captioned leases. All wells which were producing as of the effective date were classified as Proved Developed Producing. No nonproducing or undeveloped locations were evaluated and were not included in this analysis.

 
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Gleason Engineering


Capital Requirements

The Reserves presented in the Table of Estimated Gross and Net Remaining Reserves are reported for Proved Developed Producing only. Therefore no capital costs are required for the recovery of these estimated reserves. Plugging costs were not included in this analysis. It has been assumed that salvable equipment will yield sufficient value to offset any plugging and abandonment costs required to plug these wells.

Reserve Definitions

The proved reserves, which are attributable to the wells reviewed by Gleason Engineering, conform to the definition as set forth in the Securities and Exchange Commission’s Regulation S-X Part 210.4-10 (a) as clarified by subsequent Commission Staff Accounting Bulletins and are based on the following definition and criteria:

Proved reserves of crude oil, condensate, natural gas, and natural gas liquids are estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under existing 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 escalation based on future conditions. Reservoirs are considered proved if either actual production or conclusive formation test supports economic producibility. In certain instances, proved reserves are assigned on the basis of a combination of core analysis and electrical and other type logs which indicate the reservoirs are analogous to reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. The area of a reservoir considered proved includes (1) that portion delineated by drilling and defined by fluid contacts, if any, and (2) the adjoining portions not yet drilled that can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of data on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proven limit of the reservoir. Reserves that can be produced economically through the application of improved recovery techniques are included in the proved classification when these qualifications are met: (1) successful testing by a pilot project or the operation of an installed program I the reservoir provides support for the engineering analysis on which the project or program was based, and (2) it is reasonably certain the project will proceed. Improved recovery includes all methods for supplementing natural reservoir forces and energy, or otherwise increasing ultimate recovery from a reservoir, including (1) pressure maintenance, (2) cycling, and (3) secondary recovery in its original sense. Improved recovery also includes the enhanced recovery methods of thermal, chemical flooding, and the use of miscible and immiscible displacement fluids. Proved natural gas reserves are comprised of non-associated, associated and dissolved gas. An appropriate reduction in gas reserves has been made for the expected removal of natural gas liquids, for lease and plant fuel, and for the exclusion of non-hydrocarbon gases if they occur in significant quantities and are removed prior to sale. Estimates of proved reserves do not include crude oil, natural gas, or natural gas liquids being held in underground or surface storage. Proved reserves are estimates of hydrocarbons to be recovered from a given date forward. They may be revised as hydrocarbons are produced and additional data become available.

Proved developed oil and gas reserves are reserves that can 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. Developed reserves may be subcategorized as producing or non-producing using the SPE Definitions:

 
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Gleason Engineering


• Producing - Reserves sub-categorized as producing are expected to be recovered from completion intervals, which are open and producing at the time of the estimate. Improved  recovery reserves are considered producing only after the improved recovery project is in operation.

• Non-Producing – Reserves sub-categorized as non-producing include shut-in and behind pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind pipe reserves are reserves that are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production.

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 reasonable certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are attributable to any acreage for which an application of fluid injection or other improved technique is contemplated, only when such techniques have been proved effective by actual tests in the area and in the same reservoir.

Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable. In this context, when probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves.

In general, probable reserves may include (1) reserves anticipated to be proved by normal step-out drilling where sub-surface control is inadequate to classify these reserves as proved, (2) reserves in formations that appear to be productive based on well log characteristics but lack core data or definitive tests and which are not analogous to producing or proved reservoirs in the area, (3) incremental reserves attributable to infill drilling that could have been classified as proved if closer statutory spacing had been approved at the time of the estimate, (4) reserves attributable to improved recovery methods that have been established by repeated commercially successful applications when (a) a project or pilot is planned but not in operation and (b) rock, fluid, and reservoir characteristics appear favorable for commercial application, (5) reserves in an area of the formation that appears to be separated from the proved area by faulting and the geologic interpretation indicates the subject area is structurally higher than the proved area, (6) reserves attributable to a future workover, treatment, re-treatment, change of equipment, or other mechanical procedures, where such procedure has not been proved successful in wells which exhibit similar behavior in analogous reservoirs, and (7) incremental reserves in proved reservoirs where an alternative interpretation of performance or volumetric data indicates more reserves than can be classified as proved.

General

The estimates of reserves for the wells and locations reviewed by Gleason Engineering are based on data generally available through November 30, 2012.
 
 
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Gleason Engineering


Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

This report was prepared for the exclusive use and sole benefit of HKN Bakken, Inc. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
 
 
 
Sincerely,
 
/s/ Dennis M Gleason  
Dennis M Gleason, PE
Gleason Engineering