Attached files
file | filename |
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S-1/A - FORM S-1/A - Mid-Con Energy Partners, LP | h83468a1sv1za.htm |
EX-23.2 - EX-23.2 - Mid-Con Energy Partners, LP | h83468a1exv23w2.htm |
EX-10.6 - EX-10.6 - Mid-Con Energy Partners, LP | h83468a1exv10w6.htm |
EX-23.1 - EX-23.1 - Mid-Con Energy Partners, LP | h83468a1exv23w1.htm |
Exhibit 99.2
Cawley, Gillespie & Associates, Inc.
petroleum consultants
petroleum consultants
9601 AMBERGLEN BLVD., SUITE 117
|
306 WEST SEVENTH STREET, SUITE 302 | 1000 LOUISIANA STREET, SUITE 625 | ||
AUSTIN, TEXAS 78729-1106
|
FORT WORTH, TEXAS 76102-4987 | HOUSTON, TEXAS 77002-5008 | ||
512-249-7000
|
817- 336-2461 | 713-651-9944 | ||
www.cgaus.com |
July 18, 2011
Mr. Robbin W. Jones
Vice President & COO
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
2431 E. 61st St., Suite 850
Tulsa, Oklahoma 74136
Vice President & COO
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
2431 E. 61st St., Suite 850
Tulsa, Oklahoma 74136
Re: Reserve Audit
Mid-Con Energy I, LLC and
Mid-Con Energy II, LLC Interests
Total Proved Reserves
As of December 31, 2010
Mid-Con Energy I, LLC and
Mid-Con Energy II, LLC Interests
Total Proved Reserves
As of December 31, 2010
Pursuant to the Guidelines of the
Securities and Exchange Commission for
Reporting Corporate Reserves and
Future Net Revenue
Securities and Exchange Commission for
Reporting Corporate Reserves and
Future Net Revenue
Dear Mr. Jones:
At your request, this letter was prepared for Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
(MCE) on July 18, 2011 for the purpose of describing our audit of your estimates of proved
reserves and forecasts of economics attributable to the subject interests. We examined 100% of MCE
reserves, which are made up of oil and gas properties in various fields in Oklahoma and Colorado.
This examination utilized an effective date of December 31, 2010, was prepared using constant
prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the
Securities and Exchange Commission (SEC). Our examination included all methods and procedures as we
considered necessary under the circumstances to render the opinion set forth herein. The estimates
as prepared by MCE are summarized as follows:
Cumulative | ||||||||||||||||
Net | Net | Cash Flow | ||||||||||||||
Oil | Gas | Net | Disc. @ 10% | |||||||||||||
(Mbbls) | (MMcf) | MBOE | (M$) | |||||||||||||
Total Proved |
6,938 | 1,070 | 7,116 | 183,204 | ||||||||||||
Proved Developed Producing |
2,559 | 1,083 | 2,738 | 66,150 | ||||||||||||
Proved Developed Non-Producing |
870 | -1 | 870 | 31,578 | ||||||||||||
Proved Developed Behind Pipe |
102 | 0 | 102 | 2,601 | ||||||||||||
Proved Undeveloped |
3,407 | -12 | 3,406 | 82,876 |
Future revenue is prior to deducting state production taxes and ad valorem taxes. Future
net cash flow is after deducting these taxes, future capital costs and operating expenses, but
before consideration of
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federal income taxes. In accordance with SEC guidelines, the future net cash flow has been
discounted at an annual rate of ten 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.
The oil reserves include oil and condensate. Oil volumes are expressed in barrels (42 U.S.
gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract
temperature and pressure base. Our audit involved proved reserves only and did not include any
probable or possible reserves nor have any values been attributed to interest in acreage beyond the
location for which undeveloped reserves have been estimated.
Hydrocarbon Pricing
The base SEC oil and gas prices calculated December 31, 2010 were $79.43/bbl and
$4.37/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average
price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each
month within the 12-month period prior to the end of the reporting period. The base oil and gas
prices are based upon WTI-Cushing and Henry Hub spot prices, respectively, as published by the EIA
for January 1, 2010 through December 1, 2010.
The base prices shown above were adjusted for differentials on a per-property basis, which may
include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content)
and/or crude quality and gravity corrections. After these adjustments, the net realized prices for
the SEC price case over the life of the proved properties was estimated to be $74.26 per barrel for
oil and $7.36 per MCF for gas. All economic factors were held constant in accordance with
SEC guidelines.
Economic Parameters
Ownership was accepted as furnished and has not been independently confirmed. Oil and gas
price differentials, gas shrinkage, ad valorem taxes, severance taxes, lease operating expenses and
investments were calculated and prepared by MCE and were reviewed by us for reasonableness. Lease
operating expenses were either determined at the field or individual well level using averages
calculated from historical lease operating statements. All economic parameters, including lease
operating expenses and investments, were held constant (not escalated) throughout the life of these
properties.
SEC Conformance and Regulations
The reserve classifications and the economic considerations used herein conform to the
criteria of the SEC as defined in pages 6 and 7 following this letter. The reserves and economics
are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties
currently in effect except as noted herein. Government policies and market conditions different
from those employed in this report may cause (1) the total quantity of oil or gas to be recovered,
(2) actual production rates, (3) prices received, or (4) operating and capital costs to vary from
those presented in this report. However, we do not anticipate nor are we aware of any legislative
changes or restrictive regulatory actions that may impact the recovery of reserves.
This evaluation includes 73.5 proved undeveloped locations, which includes four (4) locations
in the Harker Ranch Field in Colorado and 69.5 locations in various fields in Oklahoma. Each of
these drilling locations proposed as part of MCEs development plans conforms to the proved
undeveloped standards as
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set forth by the SEC. In our opinion, MCE has indicated they have every intent to complete this
development plan within the next five years. Furthermore, MCE has demonstrated that they have the
proper company staffing, financial backing and prior development success to ensure this five year
development plan will be fully executed.
Reserve Estimation Methods
The methods employed in estimating reserves are described in page 5 following this letter.
Reserves for proved developed producing wells were estimated using production performance methods
for the vast majority of properties. Certain new producing properties with very little production
history were forecast using a combination of production performance and analogy to similar
production, both of which are considered to provide a relatively high degree of accuracy.
Non-producing reserve estimates, for both developed and undeveloped properties, were forecast
using either volumetric or analogy methods, or a combination of both. For certain fields either
waterflooding or preparing for a waterflood, proved undeveloped reserves were based upon results
from either a pilot waterflood (in the field) or an analogous, nearby waterflood deemed to be
relevant. These methods provide a relatively high degree of accuracy for predicting proved
developed non-producing and proved undeveloped reserves for MCE properties, due to the mature
nature of their properties targeted for development and an abundance of subsurface control data.
The assumptions, data, methods and procedures used herein are appropriate for the purpose served by
this audit.
General Discussion
An on-site field inspection of the properties has not been performed. The mechanical operation
or condition of the wells and their related facilities have not been examined nor have the
wells been tested by Cawley, Gillespie & Associates, Inc. (CG&A) Possible environmental liability
related to the properties has not been investigated nor considered. The cost of plugging and the
salvage value of equipment at abandonment have not been included.
The estimates and forecasts were based upon interpretations of data furnished by your office
and available from our files. To some extent information from public records has been used to check
and/or supplement these data. The basic engineering and geological data were subject to third party
reservations and qualifications. Nothing has come to our attention, however, that would cause us to
believe that we are not justified in relying on such data. All estimates represent our best
judgment based on the data available at the time of preparation. Due to inherent uncertainties in
future production rates, commodity prices and geologic conditions, it should be realized that the
reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual
cost incurred could be more or less than the estimated amounts.
It should be understood that our audit and the development of our reserves forecasts do not
constitute a complete reserve study of the oil and gas properties of MCE. In the conduct of our
audit, we have not independently verified the accuracy and completeness of information and data
furnished by MCE with respect to ownership interests, oil and gas production, historical costs of
operation and developments, product prices, agreements relating to current and future operations
and sales of production. Furthermore, if in the course of our examination something came to our
attention which brought into question the validity or sufficiency of any of such information or
data, we did not rely on
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such information or data until we had satisfactorily resolved our questions relating thereto or
independently verified such information or data.
Please be advised that, based upon the foregoing, in our opinion the above-described estimates
of Mid-Con Energy I, LLC and Mid-Con Energy II, LLCs total proved reserves are, in the aggregate,
reasonable within the established audit tolerance guidelines of (+ or ) 10%. Also, these
estimates have been prepared in accordance with generally accepted petroleum engineering and
evaluation principles as set forth in the Standards Pertaining to the Estimating and Auditing of
Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers and as mandated
by the SEC.
Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up
of independent registered professional engineers and geologists that have provided petroleum
consulting services to the oil and gas industry for over 50 years. This evaluation was supervised
by Robert D. Ravnaas, Executive Vice President at Cawley, Gillespie & Associates, Inc. and a State
of Texas Licensed Professional Engineer (License #61304). We do not own an interest in the
properties, Mid-Con Energy I, LLC or Mid-Con Energy II, LLC and are not employed on a contingent
basis. We have used all methods and procedures that we consider necessary under the circumstances
to prepare this audit. Our work-papers and related data utilized in the preparation of these
estimates are available in our office.
Sincerely, | ||
CAWLEY, GILLESPIE & ASSOCIATES, INC. | ||
Robert D. Ravnaas, P.E. | ||
Executive Vice President |
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Methods Employed in the Estimation of Reserves
The four methods customarily employed in the estimation of reserves are (1) production
performance, (2) material balance, (3) volumetric and (4) analogy.
Most estimates, although based primarily on one method, utilize other methods depending on the
nature and extent of the data available and the characteristics of the reservoirs.
Basic information includes production, pressure, geological and laboratory data. However, a
large variation exists in the quality, quantity and types of information available on individual
properties. Operators are generally required by regulatory authorities to file monthly production
reports and may be required to measure and report periodically such data as well pressures,
gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in
obtaining and/or making available geological and engineering data. The resulting lack of
uniformity in data renders impossible the application of identical methods to all properties, and
may result in significant differences in the accuracy and reliability of estimates.
A brief discussion of each method, its basis, data requirements, applicability and
generalization as to its relative degree of accuracy follows:
Production performance. This method employs graphical analyses of production data on
the premise that all factors which have controlled the performance to date will continue to control
and that historical trends can be extrapolated to predict future performance. The only information
required is production history. Capacity production can usually be analyzed from graphs of rates
versus time or cumulative production. This procedure is referred to as decline curve analysis.
Both capacity and restricted production can, in some cases, be analyzed from graphs of producing
rate relationships of the various production components. Reserve estimates obtained by this method
are generally considered to have a relatively high degree of accuracy with the degree of accuracy
increasing as production history accumulates.
Material balance. This method employs the analysis of the relationship of production
and pressure performance on the premise that the reservoir volume and its initial hydrocarbon
content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be
estimated by analyzing changes in pressure with respect to production relationships. This method
requires reliable pressure and temperature data, production data, fluid analyses and knowledge of
the nature of the reservoir. The material balance method is applicable to all reservoirs, but the
time and expense required for its use is dependent on the nature of the reservoir and its fluids.
Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for
compressibility versus cumulative production, requiring only data that are usually available.
Estimates for other reservoir types require extensive data and involve complex calculations most
suited to computer models which makes this method generally applicable only to reservoirs where
there is economic justification for its use. Reserve estimates obtained by this method are
generally considered to have a degree of accuracy that is directly related to the complexity of the
reservoir and the quality and quantity of data available.
Volumetric. This method employs analyses of physical measurements of rock and fluid
properties to calculate the volume of hydrocarbons in-place. The data required are well
information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid
content and location. The volumetric method is most applicable to reservoirs which are not
susceptible to analysis by production performance or material balance methods. These are most
commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons
in-place that can be recovered is not an integral part of the volumetric calculations but is an
estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve
estimates obtained by this method are generally considered to have a low degree of accuracy; but
the degree of accuracy can be relatively high where rock quality and subsurface control is good and
the nature of the reservoir is uncomplicated.
Analogy. This method which employs experience and judgment to estimate reserves, is
based on observations of similar situations and includes consideration of theoretical performance.
The analogy method is applicable where the data are insufficient or so inconclusive that reliable
reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are
generally considered to have a relatively low degree of accuracy.
Much of the information used in the estimation of reserves is itself arrived at by the use of
estimates. These estimates are subject to continuing change as additional information becomes
available. Reserve estimates which presently appear to be correct may be found to contain
substantial errors as time passes and new information is obtained about well and reservoir
performance.
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Reserve Definitions and Classifications
The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as
amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions
of oil and gas reserves:
(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 produciblefrom 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 a 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.
(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.
(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.
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(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 (17)(iv) and (17)(vi) of this section (below).
(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 (22)(iii) of this section (above), 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.
Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised
January 1, 2010 to state that a registrant engaged in oil and gas producing activities shall
provide the information required by Subpart 1200 of Regulation SK. This is relevant in that
Instruction 2 to paragraph (a)(2) states: The registrant is permitted, but not required, to
disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of
this Item.
(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 (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).