EXHIBIT 99.1
Mr. Paul Laird
September 26, 2013
GUSTAVSON ASSOCIATES
Geologists - engineers - economists - appraisers
September 26, 2013
Mr. Paul Laird
Natural Resources Group, Inc.
1789 West Littleton Boulevard
Littleton, CO 80120
Subject: Reserve Estimate and Financial Forecast as to Natural Resources
Group's Net Interests in the Garcia Field, Las Animas County, Colorado
as of October 31, 2012
Dear Paul:
As you requested, Gustavson Associates has conducted an independent reserve
evaluation and estimated the future revenue attributable as to Natural Resources
Group's net interest in future gas and natural gas liquids (NGL) production
associated with the leases in the Garcia Field, Las Animas County, Colorado.
Reserves have been estimated based on a probabilistic analysis of the gas
reserves based on a volumetric calculation, combined with analysis of the
production data from the producing wells. Uncertainties were considered in
productive field area, net pay, porosity, water saturation, and recovery factor.
Estimates and projections have been made as of October 31, 2012. Reserves have
been estimated in accordance with the United States Securities and Exchange
Commission (SEC) definitions and guidelines.
Although at the effective date four wells were producing, with NGLs being
stripped and the gas reinjected, the forecast of this production stream into the
future cannot be considered as Proved Developed Producing reserves (PDP),
because our analysis indicates that the operations were not economic. After the
planned installation of a different gas plant with the ability to extract more
NGLs from the gas, and a gas pipeline to allow sales of the residue gas, these
wells are expected to be economic. Therefore, the reserves associated with the
currently producing wells are considered to be Proved Undeveloped (PUD). We note
that these four wells have produced for over two years with no decline in
production rate and no decline in the BTU content of the produced gas. A 5% per
year decline was assumed for the forecast in this report. In addition, PUD
reserves have been assigned to the current injection well, and to 25 additional
locations planned to be drilled by Natural Resources Group, offset to currently
producing wells or twinning or adjacent to older abandoned wells with reported
well test data supporting commercial rates under current market conditions.
Probable and Possible reserves have been assigned to the currently producing
wells, to the PUD well locations, and to additional locations, based on a
probabilistic volumetric calculation. The Proved plus Probable (2P) and Proved
plus Probable plus Possible (3P) scenarios also include production from the
current gas injection well after the construction of the gas pipeline. Producing
and past producing well locations as well as undeveloped locations are shown on
Figure 1.
1
The estimated net reserves volumes and associated net cash flow estimates are
summarized below.
Summary of Net Reserves and Projected Before Tax Cash Flow
Number
Number of Net Gas Net NGL Net Present Value,
of Total Wells Reserves, Reserves, thousands of US$
Reserves Category Wells Drilled MMCF Mgal Discounted at
0% 10% 15%
Flat Pricing
Proved 30 25 560 5,724 1,201 -76 -441
Undeveloped
Probable 1 1 610 5,833 5,578 2,880 2,171
Proved + Probable 31 26 1,170 11,558 6,779 2,804 1,730
Possible 7 7 767 7,259 6,481 2,597 1,754
Proved +
Probable + 38 33 1,938 18,816 13,260 5,400 3,484
Possible
Forecast Pricing
Proved 30 25 560 5,724 7,206 3,605 2,530
Undeveloped
Probable 1 1 610 5,833 14,169 6,930 5,097
Proved + Probable 31 26 1,170 11,558 21,374 10,535 7,627
Possible 7 7 774 7,325 18,868 7,325 4,912
Proved +
Probable + 38 33 1,945 18,883 40,243 17,860 12,539
Possible
Drilling was assumed to begin with one well each in August and September 2013,
with expected drilling and completion costs of $87M per well. A ten-well
drilling program is planned for January 2014. A hiatus of five months is assumed
before beginning a continuous drilling program for the remainder of the
locations. It is expected to require only three days to drill and complete each
well to a depth of about 1,500 feet. The development scenario was based on
discussions with NRG. Operating costs (well operating costs and gas plant and
compression rental costs) and capital costs (well drilling and completion costs
and pipeline construction and hookup costs) were also provided by NRG and appear
to be reasonable. Other assumptions are detailed in Table 1 below.
2
Table 1 Economic Assumptions
As of date 10/31/2012
WI 100.00%
Royalty Burden on 8/8ths 18.75%
NRI 81.25%
Production tax rate 4.00%
Per Well Drilling & Compl Costs, M$ 87.1
Liquid Storage Tank, M$ 0.0
Pipeline Cost, M$ 1,300.0
Number of Wells producing before pipeline 30
Gas Sales Start Aug-14
Lease for Plant and Compressors, M$/mo 6.0 Oct-12
8.0 Dec-12 & thereafter
Four-well Operating Costs, $/mo 1,100
Additional Operating Costs, $/well/mo 80
BTU Content Sales Gas, MMBTU/MCF 1.176
NGL Yield, gals/MCF 1.45 Oct-12
5.00 Dec-12 & thereafter
NGL transportation & handling fee, $/gal 0.284
NGL processing fee, % 1.5%
Percent Produced Gas Sold (after 53.5%
shrinkage/fuel)
Cost Escalation 2.5%
Two pricing cases were evaluated. For the flat pricing case, prices are to be
based on the average of the prices from the first day of each of the 12 months
previous to the effective date. However, because only NGLs have been sold to
date from the Garcia Field and the sales have not occurred in each month, these
average prices must be estimated. The flat NGL prices were based on the average
NGL prices actually received over the past year of revenue statements, divided
by the average Henry Hub spot price for the same months with NGL sales,
multiplied by the average of the Henry Hub prices from the first day of each of
the previous 12 months. Flat natural gas prices were based on the average of the
Henry Hub prices from the first day of each of the previous 12 months, adjusted
by an estimated average differential between Henry Hub and Colorado gas pricing
of -0.20 $/MMBTU, adjusted for the estimated BTU content of the residue gas. For
the forecast pricing case, a forecast for wellhead gas was prepared based on the
NYMEX futures strips for two weeks prior to the effective date for Henry Hub
less the futures strip for the Colorado Interstate Gas (CIG) differential,
adjusted for the expected BTU content of the residue gas. NGL pricing for the
forecast case was based on the ratio of historical NGL prices to Henry Hub spot
prices applied to the Henry Hub forecast. Prices were held constant after the
end of the futures strip data.
We have reviewed geologic maps and cross-sections provided by NRG, older well
initial potential data, and published reports about the field in forming our
opinion of reserves. A summary cash flow for each category is included in Tables
2 through 7.
3
Limiting Conditions and Disclaimers
The accuracy of any reserve report or resource evaluation is a function of
available data and of engineering and geologic interpretation and judgment.
While the evaluation presented herein is believed to be reasonable, it should be
viewed with the understanding that subsequent reservoir performance or changes
in pricing structure, market demand, or other economic parameters may justify
its revision.
Gustavson Associates, LLC, holds neither direct nor indirect financial interest
in the subject property, the company operating the subject acreage, or in any
other affiliated companies.
All data and work files utilized in the preparation of this report are available
for examination in our offices. Please contact us if we can be of assistance. We
appreciate the opportunity to be of service and look forward to further serving
Natural Resources Group.
Sincerely,
GUSTAVSON ASSOCIATES, LLC.
/s/ Letha C. Lencioni
-------------------------------------
Letha C. Lencioni, P.E.
Vice-President, Petroleum Engineering
Registered Professional Engineer, State of Colorado, # 29506