EXHIBIT 99.1

 

	Moyes & Co.
	http://www.moyesco.com

 

 

January 28, 2015

 

Ms. Deb Tate

HKN, INC.

180 State Street, Suite 200

Southlake, TX 76092

 

Dear Ms. Deb Tate:

 

In accordance with your request, we have estimated the proved reserves and future revenue, as of January 01, 2015, to the HKN, INC. interest in certain oil & gas properties located in North Dakota, Colorado, and Texas as listed in the accompanying tabulations. This report has been prepared using SEC regulation 12-month un-weighted average of first-day-of-the-month prices and costs, as discussed in subsequent paragraphs of this letter. The estimates of reserves and future revenue in this report have otherwise been prepared in accordance with the SEC guidelines. Definitions are presented immediately following this letter.

 

As presented in the accompanying summary projections, we estimate the net reserves and future net revenue to the HKN, INC. interest in these properties, as of January 01, 2015, to be:

 

Grand Total As of January 01, 2015
		Gross Reserves				Net Reserves				Net Cash Flow
Reserve Class / Category		Oil & Condensate (Mbbl)		Natural Gas (MMcf)		Oil & Condensate (Mbbl)		Natural Gas (MMcf)		Future Net Revenue ($000)		Future Net OPEX & Taxes ($000)		Future Net Capital ($000)		Future Net Cash Flow ($000)		NPV Disc @ 10% ($000)
Proved Developed Producing		16,788		32,173		44		68		4,124		1,169		-		2,955		1,926
Proved Developed Behind Pipe		2,956		5,913		2		4		224		58		-		166		113
Proved Shut In		-		-		-		-		-		-		-		-		-
Proved Undeveloped		14,848		30,505		71		134		6,993		1,647		1,902		3,444		1,657
Total Proved		34,592		68,591		117		206		11,341		2,874		1,902		6,565		3,696

 

The estimates shown in this report are for proved developed producing, proved non-producing, proved shut-in, and proved undeveloped. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves sub-categorization is based on development and production status. The estimates of proved reserves and future revenue included herein have not been adjusted for risk. For each reserves category this report includes a summary projection of reserves and revenue.

 

The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

 

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and their related facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. Our estimates of future revenue do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

 

Constant prices were used for each area in this report based on posted prices of crude oil and natural gas using a 12 month unweighted arithmetic average closing price of each commodity on the first day of each month from January 1, 2014 through December 1, 2014, in accordance with SEC guidelines. These base prices are calculated as $91.48/bbl of oil and $4.35/MMBTU of natural gas. Oil and natural gas price differentials are estimated in the economics from lease operating statements provided by HKN. Natural gas price differentials are also adjusted for NGL content as necessary. Operating and estimated future capital costs are based on lease operating statements and AFE’s provided by HKN. North Dakota differentials are estimated at -$8.01/bbl and +$3.54/Mcf. Texas price differentials are estimated at -$10.75/bbl and +$1.33/Mcf. Colorado oil differentials are estimated at -$9.01/bbl while gas differentials were determined on a per well basis due to a large range of varying pricing as a result of NGL recovery. Colorado gas differentials range from -$0.16/Mcf to +$4.34/Mcf.

 

The reserves shown in this report are estimates only and should not be construed as exact quantities. The reserves may or may not be recoverable; if they are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report. Also, estimates of reserves may increase or decrease as a result of future operations.

 

In evaluating the information at our disposal concerning this report, we have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting, rather than engineering and geologic. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geologic data; therefore, our conclusions necessarily represent only informed professional judgment.

 

The titles to the properties have not been examined by Moyes & Company, nor has the actual degree or type of interest owned been independently confirmed. The data used in our estimates were obtained from HKN, INC. and were accepted as accurate. Supporting geologic field performance, and work data are on file in our office. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties and are not employed on a contingent basis.

 

Sincerely,

 

/s/ P. Dee Patterson P. Dee Patterson, P.E. Managing Director Moyes & Co., dpatterson@moyesco.com

 

Table of Contents

1.	Definitions of Oil and Gas Reserves	4
2.	Determination of Reserves and Cash Flows	10
3.	Reserves Breakdown by Reservoir	11

 

 

Definitions of Oil and Gas Reserves

 

Adapted from the 2007 Petroleum Resources Management System (PRMS) Approved by the Society of Petroleum Engineers (SPE)

 

Petroleum Resources Classification Framework

 

Petroleum is defined as a naturally occurring mixture consisting of hydrocarbons in the gaseous, liquid, or solid phase. Petroleum may also contain non-hydrocarbons, common examples of which are carbon dioxide, nitrogen, hydrogen sulfide and sulfur. In rare cases, non-hydrocarbon content could be greater than 50%.

 

The term “resources” as used herein is intended to encompass all quantities of petroleum naturally occurring on or within the Earth’s crust, discovered and undiscovered (recoverable and unrecoverable), plus those quantities already produced. Further, it includes all types of petroleum whether currently considered “conventional” or “unconventional.”

 

Figure 1-1 is a graphical representation of the SPE/WPC/AAPG/SPEE resources classification system. The system defines the major recoverable resources classes: Production, Reserves, Contingent Resources, and Prospective Resources, as well as Unrecoverable petroleum.

 

 

 

The “Range of Uncertainty” reflects a range of estimated quantities potentially recoverable from an accumulation by a project, while the vertical axis represents the “Chance of Commerciality, that is, the chance that the project that will be developed and reach commercial producing status. The following definitions apply to the major subdivisions within the resources classification:

 

TOTAL PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production plus those estimated quantities in accumulations yet to be discovered (equivalent to “total resources”).

 

DISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production.

 

PRODUCTION is the cumulative quantity of petroleum that has been recovered at a given date. While all recoverable resources are estimated and production is measured in terms of the sales product specifications, raw production (sales plus non-sales) quantities are also measured and required to support engineering analyses based on reservoir voidage (see Production Measurement, section 3.2 of the official PRMS document).

 

Multiple development projects may be applied to each known accumulation, and each project will recover an estimated portion of the initially-in-place quantities. The projects shall be subdivided into Commercial and Sub-Commercial, with the estimated recoverable quantities being classified as Reserves and Contingent Resources respectively, as defined below.

 

RESERVES are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status.

 

CONTINGENT RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status.

 

UNDISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum estimated, as of a given date, to be contained within accumulations yet to be discovered.

 

PROSPECTIVE RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub-classified based on project maturity.

 

UNRECOVERABLE is that portion of Discovered or Undiscovered Petroleum Initially-in-Place quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.

 

Estimated Ultimate Recovery (EUR) is not a resources category, but a term that may be applied to any accumulation or group of accumulations (discovered or undiscovered) to define those quantities of petroleum estimated, as of a given date, to be potentially recoverable under defined technical and commercial conditions plus those quantities already produced (total of recoverable resources).

 

In specialized areas, such as basin potential studies, alternative terminology has been used; the total resources may be referred to as Total Resource Base or Hydrocarbon Endowment. Total recoverable or EUR may be termed Basin Potential. The sum of Reserves, Contingent Resources, and Prospective Resources may be referred to as “remaining recoverable resources.” When such terms are used, it is important that each classification component of the summation also be provided. Moreover, these quantities should not be aggregated without due consideration of the varying degrees of technical and commercial risk involved with their classification.

 

Resources Categorization

The horizontal axis in the Resources Classification (Figure 1.1) defines the range of uncertainty in estimates of the quantities of recoverable, or potentially recoverable, petroleum associated with a project. These estimates include both technical and commercial uncertainty components as follows:

 

·

The total petroleum remaining within the accumulation (in-place resources).

·

That portion of the in-place petroleum that can be recovered by applying a defined development project or projects.

·

Variations in the commercial conditions that may impact the quantities recovered and sold (e.g., market availability, contractual changes).

 

Where commercial uncertainties are such that there is significant risk that the complete project (as initially defined) will not proceed, it is advised to create a separate project classified as Contingent Resources with an appropriate chance of commerciality.

 

Range of Uncertainty

The range of uncertainty of the recoverable and/or potentially recoverable volumes may be represented by either deterministic scenarios or by a probability distribution (see Deterministic and Probabilistic Methods, section 4.2 of the official PRMS document).

 

When the range of uncertainty is represented by a probability distribution, a low, best, and high estimate shall be provided such that:

 

·

There should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed the low estimate.

·

There should be at least a 50% probability (P50) that the quantities actually recovered will equal or exceed the best estimate.

·

There should be at least a 10% probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

 

When using the deterministic scenario method, typically there should also be low, best, and high estimates, where such estimates are based on qualitative assessments of relative uncertainty using consistent interpretation guidelines. Under the deterministic incremental (risk-based) approach, quantities at each level of uncertainty are estimated discretely and separately (see Category Definitions and Guidelines, section 2.2.2 of the official PRMS document).

 

These same approaches to describing uncertainty may be applied to Reserves, Contingent Resources, and Prospective Resources. While there may be significant risk that sub-commercial and undiscovered accumulations will not achieve commercial production, it useful to consider the range of potentially recoverable quantities independently of such a risk or consideration of the resource class to which the quantities will be assigned.

 

Category Definitions and Guidelines

Evaluators may assess recoverable quantities and categorize results by uncertainty using the deterministic incremental (risk-based) approach, the deterministic scenario (cumulative) approach, or probabilistic methods. (see “2001 Supplemental Guidelines,” Chapter 2.5). In many cases, a combination of approaches is used.

 

Use of consistent terminology (Figure 1.1) promotes clarity in communication of evaluation results. For Reserves, the general cumulative terms low/best/high estimates are denoted as 1P/2P/3P, respectively. The associated incremental quantities are termed Proved, Probable and Possible. Reserves are a subset of, and must be viewed within context of, the complete resources classification system. While the categorization criteria are proposed specifically for Reserves, in most cases, they can be equally applied to Contingent and Prospective Resources conditional upon their satisfying the criteria for discovery and/or development.

 

For Contingent Resources, the general cumulative terms low/best/high estimates are denoted as 1C/2C/3C respectively. For Prospective Resources, the general cumulative terms low/best/high estimates still apply. No specific terms are defined for incremental quantities within Contingent and Prospective Resources.

 

Without new technical information, there should be no change in the distribution of technically recoverable volumes and their categorization boundaries when conditions are satisfied sufficiently to reclassify a project from Contingent Resources to Reserves. All evaluations require application of a consistent set of forecast conditions, including assumed future costs and prices, for both classification of projects and categorization of estimated quantities recovered by each project (see Commercial Evaluations, section 3.1 of the official PRMS document).

 

The following summarizes the definitions for each Reserves category in terms of both the deterministic incremental approach and scenario approach and also provides the probability criteria if probabilistic methods are applied.

 

·

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. If deterministic methods are used, the term reasonable certainty is intended to express 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.

·

Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate.

·

Possible Reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than Probable Reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P) Reserves, which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate.

 

 

Based on additional data and updated interpretations that indicate increased certainty, portions of Possible and Probable Reserves may be re-categorized as Probable and Proved Reserves.

 

Uncertainty in resource estimates is best communicated by reporting a range of potential results. However, if it is required to report a single representative result, the “best estimate” is considered the most realistic assessment of recoverable quantities. It is generally considered to represent the sum of Proved and Probable estimates (2P) when using the deterministic scenario or the probabilistic assessment methods. It should be noted that under the deterministic incremental (risk-based) approach, discrete estimates are made for each category, and they should not be aggregated without due consideration of their associated risk (see “2001 Supplemental Guidelines,” Chapter 2.5).

 

Commercial Evaluations

Investment decisions are based on the entity’s view of future commercial conditions that may impact the development feasibility (commitment to develop) and production/cash flow schedule of oil and gas projects. Commercial conditions include, but are not limited to, assumptions of financial conditions (costs, prices, fiscal terms, taxes), marketing, legal, environmental, social, and governmental factors. Project value may be assessed in several ways (e.g., historical costs, comparative market values); the guidelines herein apply only to evaluations based on cash flow analysis. Moreover, modifying factors such contractual or political risks that may additionally influence investment decisions are not addressed. (Additional detail on commercial issues can be found in the “2001 Supplemental Guidelines,” Chapter 4.)

 

Cash-Flow-Based Resources Evaluations

Resources evaluations are based on estimates of future production and the associated cash flow schedules for each development project. The sum of the associated annual net cash flows yields the estimated future net revenue. When the cash flows are discounted according to a defined discount rate and time period, the summation of the discounted cash flows is termed net present value (NPV) of the project. The calculation shall reflect:

 

 

·

The expected quantities of production projected over identified time periods.

·

The estimated costs associated with the project to develop, recover, and produce the quantities of production at its Reference Point (see section 3.2.1 of the official PRMS document), including environmental, abandonment, and reclamation costs charged to the project, based on the evaluator’s view of the costs expected to apply in future periods.

·

The estimated revenues from the quantities of production based on the evaluator’s view of the prices expected to apply to the respective commodities in future periods including that portion of the costs and revenues accruing to the entity.

·

Future projected production and revenue related taxes and royalties expected to be paid by the entity.

·

A project life that is limited to the period of entitlement or reasonable expectation thereof.

·

The application of an appropriate discount rate that reasonably reflects the weighted average cost of capital or the minimum acceptable rate of return applicable to the entity at the time of the evaluation.

·

While each organization may define specific investment criteria, a project is generally considered to be “economic” if its “best estimate” case has a positive net present value under the organization’s standard discount rate, or if at least has a positive undiscounted cash flow.

 

Economic Criteria

Evaluators must clearly identify the assumptions on commercial conditions utilized in the evaluation and must document the basis for these assumptions.

 

The economic evaluation underlying the investment decision is based on the entity’s reasonable forecast of future conditions, including costs and prices, which will exist during the life of the project (forecast case). Such forecasts are based on projected changes to current conditions; SPE defines current conditions as the average of those existing during the previous 12 months.

 

Alternative economic scenarios are considered in the decision process and, in some cases, to supplement reporting requirements. Evaluators may examine a case in which current conditions are held constant (no inflation or deflation) throughout the project life (constant case).

 

Evaluations may be modified to accommodate criteria imposed by regulatory agencies regarding external disclosures. For example, these criteria may include a specific requirement that, if the recovery were confined to the technically Proved Reserves estimate, the constant case should still generate a positive cash flow. External reporting requirements may also specify alternative guidance on current conditions (for example, year-end costs and prices).

 

There may be circumstances in which the project meets criteria to be classified as Reserves using the forecast case but does not meet the external criteria for Proved Reserves. In these specific circumstances, the entity may record 2P and 3P estimates without separately recording Proved. As costs are incurred and development proceeds, the low estimate may eventually satisfy external requirements, and Proved Reserves can then be assigned.

 

While SPE guidelines do not require that project financing be confirmed prior to classifying projects as Reserves, this may be another external requirement. In many cases, loans are conditional upon the same criteria as above; that is, the project must be economic based on Proved Reserves only. In general, if there is not a reasonable expectation that loans or other forms of financing (e.g., farm-outs) can be arranged such that the development will be initiated within a reasonable timeframe, then the project should be classified as Contingent Resources. If financing is reasonably expected but not yet confirmed, the project may be classified as Reserves, but no Proved Reserves may be reported as above.

 

Economic Limit

Economic limit is defined as the production rate beyond which the net operating cash flows from a project, which may be an individual well, lease, or entire field, are negative, a point in time that defines the project’s economic life. Operating costs should be based on the same type of projections as used in price forecasting. Operating costs should include only those costs that are incremental to the project for which the economic limit is being calculated (i.e., only those cash costs that will actually be eliminated if project production ceases should be considered in the calculation of economic limit). Operating costs should include fixed property-specific overhead charges if these are actual incremental costs attributable to the project and any production and property taxes but, for purposes of calculating economic limit, should exclude depreciation, abandonment and reclamation costs, and income tax, as well as any overhead above that required to operate the subject property itself. Operating costs may be reduced, and thus project life extended, by various cost-reduction and revenue-enhancement approaches, such as sharing of production facilities, pooling maintenance contracts, or marketing of associated non-hydrocarbons (see Associated Non-Hydrocarbon Components, section 3.2.4 of the official PRMS document).

 

Interim negative project net cash flows may be accommodated in short periods of low product prices or major operational problems, provided that the longer-term forecasts must still indicate positive economics.

 

 

Determination of Reserves and Cash Flows

Proved developed producing (PDP) reserves were determined using decline curve analysis based on historical gross production rates. Volumetric calculations were used as a boundary condition as well as to aid in the determination of reserves for any well that lacked sufficient production history for the application of decline curve analysis.

 

To determine the estimated reserves for non-producing locations and undeveloped locations, Moyes performed an analysis of producing Bakken wells in North Dakota. 5,127 wells with sufficient production information were forecasted and a statistical analysis performed on the estimated recoveries. Moyes developed a type curve based on the statistical analysis which was used to estimate recovery for the undeveloped and confidential non-producing Bakken and Sanish Three Forks locations. Gas shrinkage from flaring and on-campus power generation is reflected in the net reserves. Any premium received for recovered NGLs or high BTU gas is reflected in the natural gas differential per HKN’s lease operating statements.

 

HKN has limited information on several wells that have been granted confidential status. Many of these wells have been spud and their current status is unknown or production has yet to begin. These wells are classified as Proved Non-Producing depending on their locations. Wells that have confidential status and are expected to have been spud or begun production but have not been confirmed are classified as Proved Undeveloped.

 

The reserves and estimated cash flows are based on a five year drilling program. Wells are estimated to be drilled at a rate of 34 per year, on average. Only locations which are considered proved have been accounted for in this report. Well capital and operating costs are based on information provided by HKN.

 

 

Reserves Breakdown by Reservoir

 

As of January 01, 2015 (Total North Dakota)
		Gross Reserves				Net Reserves				Net Cash Flow
Reserve Class / Category		Oil & Condensate (Mbbl)		Natural Gas (MMcf)		Oil & Condensate (Mbbl)		Natural Gas (MMcf)		Future Net Revenue ($000)		Future Net OPEX & Taxes ($000)		Future Net Capital ($000)		Future Net Cash Flow ($000)		NPV Disc @ 10% ($000)
Proved Developed Producing		16,384		30,503		37		47		3,445		1,017		-		2,428		1,605
Proved Developed Behind Pipe		2,956		5,912		2		4		224		58		-		166		113
Proved Shut In		-		-		-		-		-		-		-		-		-
Proved Undeveloped		14,848		30,505		71		134		6,993		1,647		1,902		3,444		1,657
Total Proved		34,187		66,920		110		185		10,662		2,722		1,902		6,038		3,374

Figure 2-1: HKN North Dakota Reserves as of January 01, 2015

 

As of January 01, 2015 (Bakken)
		Gross Reserves				Net Reserves				Net Cash Flow
Reserve Class / Category		Oil & Condensate (Mbbl)		Natural Gas (MMcf)		Oil & Condensate (Mbbl)		Natural Gas (MMcf)		Future Net Revenue ($000)		Future Net OPEX & Taxes ($000)		Future Net Capital ($000)		Future Net Cash Flow ($000)		NPV Disc @ 10% ($000)
Proved Developed Producing		12,231		22,247		34		43		3,182		960		-		2,222		1,471
Proved Developed Behind Pipe		1,418		2,836		1		2		96		23		-		72		49
Proved Shut In		-		-		-		-		-		-		-		-		-
Proved Undeveloped		9,326		18,653		59		105		5,764		1,407		1,783		2,573		1,117
Total Proved		22,975		43,735		94		150		9,042		2,391		1,783		4,868		2,637

Figure 2-2: HKN Bakken Reserves as of January 01, 2015

 

As of January 01, 2015 (Sanish / Three Forks)
		Gross Reserves				Net Reserves				Net Cash Flow
Reserve Class / Category		Oil & Condensate (Mbbl)		Natural Gas (MMcf)		Oil & Condensate (Mbbl)		Natural Gas (MMcf)		Future Net Revenue ($000)		Future Net OPEX & Taxes ($000)		Future Net Capital ($000)		Future Net Cash Flow ($000)		NPV Disc @ 10% ($000)
Proved Developed Producing		4,152		8,256		3		4		263		57		-		206		134
Proved Developed Behind Pipe		1,538		3,077		1		2		128		34		-		94		63
Proved Shut In		-		-		-		-		-		-		-		-		-
Proved Undeveloped		5,521		11,852		12		28		1,229		240		119		870		540
Total Proved		11,212		23,185		16		35		1,621		331		119		1,170		738

Figure 2-3: HKN Sanish / Three Forks Reserves as of January 01, 2015

   

As of January 01, 2015 (Total Colorado)
		Gross Reserves				Net Reserves				Net Cash Flow
Reserve Class / Category		Oil & Condensate (Mbbl)		Natural Gas (MMcf)		Oil & Condensate (Mbbl)		Natural Gas (MMcf)		Future Net Revenue ($000)		Future Net OPEX & Taxes ($000)		Future Net Capital ($000)		Future Net Cash Flow ($000)		NPV Disc @ 10% ($000)
Proved Developed Producing		190		1,481		2		18		319		126		-		194		135
Proved Developed Behind Pipe		-		-		-		-		-		-		-		-		-
Proved Shut In		-		-		-		-		-		-		-		-		-
Proved Undeveloped		-		-		-		-		-		-		-		-		-
Total Proved		190		1,481		2.5		18		319		126		-		194		135

Figure 2-4: HKN Colorado Reserves as of January 01, 2015

 

As of January 01, 2015 (Total Texas)
		Gross Reserves				Net Reserves				Net Cash Flow
Reserve Class / Category		Oil & Condensate (Mbbl)		Natural Gas (MMcf)		Oil & Condensate (Mbbl)		Natural Gas (MMcf)		Future Net Revenue ($000)		Future Net OPEX & Taxes ($000)		Future Net Capital ($000)		Future Net Cash Flow ($000)		NPV Disc @ 10% ($000)
Proved Developed Producing		214		190		4		4		359		26		-		333		187
Proved Developed Behind Pipe		-		-		-		-		-		-		-		-		-
Proved Shut In		-		-		-		-		-		-		-		-		-
Proved Undeveloped		-		-		-		-		-		-		-		-		-
Total Proved		214		190		4		4		359		26		-		333		187

Figure 2-5: HKN Texas Reserves as of January 01, 2015

 

11