ITEMS 1 AND 2. BUSINESS AND PROPERTIES.
Company History
We were formerly known as Millennium Plastics
Corporation and were incorporated in the State of Nevada on March 31, 1999. We abandoned a prior business plan focusing on the
development of biodegradable plastic materials. In August 2006, we acquired Midwest Energy, Inc., a Nevada corporation pursuant
to a reverse merger. After the merger, Midwest Energy became a wholly-owned subsidiary, and as a result of the merger the former
Midwest Energy stockholders controlled approximately 98% of our outstanding shares of common stock. We changed our name to EnerJex
Resources, Inc. in connection with the merger, and in November 2007 we changed the name of Midwest Energy (now our wholly-owned
subsidiary) to EnerJex Kansas, Inc. All of our current operations are conducted through EnerJex Kansas, Inc., Black Sable Energy,
LLC, and Black Raven Energy, Inc., and our leasehold interests are held in our wholly-owned subsidiaries Black Sable Energy, LLC,
Working Interest, LLC, EnerJex Kansas, Inc., and Black Raven Energy, Inc.
Liquidity and Ability
to Continue as a Going Concern
As discussed under
“Item 9B — Other Information” the continued low oil and natural gas prices during 2015 and into 2016 have
had a significant adverse impact on our business, and, as a result of our financial condition, substantial doubt exists that we
will be able to continue as a going concern.
On April 1, 2016 we ceased making mandatory
monthly borrowing base reduction payments on our credit facility. After discussions with our bank, we made our mandatory quarterly
interest payment on April 6, 2016 and on April 7, 2016 entered into a Forbearance Agreement (dated as of April 4, 2016), whereby
the bank agreed to not exercise remedies and rights afforded it under credit facility for thirty days. We are using this 30-day
to pursue strategic alternatives
Please read “Item 9B
— Other Information” for further discussion. Also, for additional discussion of factors that may affect our ability
to continue as a going concern and the potential consequences of our failure to do so, please see “Item 1A—Risk
Factors.”
Significant Developments in 2015
The following briefly describes our most significant corporate
developments occurring in 2015:
On March 13, 2015, the Company issued in a registered
offering 763,547 registered shares of its common stock together with 1,242.17099 shares of its newly designated Series B Convertible
Preferred Stock (the “Preferred Stock”) convertible into 709,812 shares of common stock. We also issued in an unregistered
offering, 521.62076 shares of Preferred Stock convertible into 298,069 shares of common stock, and warrants to purchase 1,771,428
shares of its common stock. The shareholder’s ability to convert a portion of the Preferred Stock and to exercise the warrant
are restricted: (i) prior to the Company obtaining approval of the offering by its shareholders, which we expect to obtain before
May 31, 2015, and (ii) pursuant to customary “blocker” provisions restricting the investor’s ownership to 9.99%
of our outstanding common stock.
The Preferred Stock has a liquidation preference
of $1,000 per share, and will be convertible at the option of the shareholder at a conversion ratio equal to approximately 571
shares of common stock for each one (1) share of Preferred Stock, subject to customary adjustments and anti-dilution price protection.
Dividends are payable on the shares of Preferred Stock only if and to the extent that dividends are payable on the common stock
into which the Preferred Stock is convertible. The Preferred Stock has no maturity date and can be redeemed by the Company beginning
twelve months after the closing of the offering or upon a change of control. Each warrant will be exercisable for one share of
common stock, for a period of five years beginning nine months after March 13, 2015, at a cash exercise price of $2.75 per share,
and may be exercised on a cashless basis after that nine-month period if no effective registration statement covers the warrant
shares by that time.
On May 13, 2015, the Company sold 183,433 shares
of its 10% Series A Cumulative Redeemable Perpetual Preferred Stock at $12.50 per share for gross proceeds of approximately $2.3
million. The Company intends to use the net proceeds of this offering for general corporate purposes, including capital expenditures,
working capital, preferred stock dividends, and repayment of outstanding borrowings under its senior credit facility.
The offering was made pursuant to a registration
statement on Form S-3 (File No. 333-199030) previously filed and declared effective by the U.S. Securities and Exchange Commission
(SEC).
On July 21, 2015, the Company received a liquidating
distribution from Oakridge Energy Inc. in the amount of $1,450,695 with respect to shares of Oakridge that are owned by the Company.
The Company repaid $750,000 of long term debt. The remaining amount will be reinvested in Company projects. The liquidating distribution
was funded from the proceeds of Oakridge’s sale of its La Plate County, Colorado property. The distribution is reflected
in the September 30, 2015 Consolidated Balance sheet as part of accounts receivable.
On August 12, 2015, we entered into a Tenth
Amendment to the Amended and Restated Credit Agreement. The Tenth Amendment reflects the following changes: (i) allow the Company
to sell certain oil assets in Kansas, (ii) allow for approximately $1,300,000 of the proceeds from the sale to be reinvested in
Company owned oil and gas projects and (iii) apply not less than $1,500,000 from the proceed of the sale to outstanding loan balances.
On August 12, 2015, EnerJex Resources, Inc.,
through its subsidiaries, EnerJex Kansas, Inc., and Working Interest, LLC, sold various oil and gas leases, equipment and wells
in Kansas for approximately $2.8 million to Haas Petroleum, LLC, BAM Petroleum, LLC and MorMeg, LLC. The effective date of the
sale was July 1, 2015.
On November 4, 2015 the Company suspended the
monthly dividend for the month of November 2015 on its 10.00% Series A Cumulative Redeemable Perpetual Preferred Stock (“Series
A Preferred Stock”) in order to preserve its cash resources. Payment of future dividends on the Series A Preferred Stock
will be determined by the Company’s Board of Directors.
Under the terms of the
Series A Preferred Stock, the dividend for the month of November 2015, and any future unpaid dividends, will accumulate. If the
Company does not pay dividends on its Series A Preferred Stock for six monthly periods (whether consecutive or non-consecutive),
the dividend rate will increase to 12.0% per annum and the holders of the Series A Preferred Stock will have the right, at the
next meeting of stockholders, to elect two directors to serve on the Company’s Board of Directors along with other members
of the Board, until all accumulated accrued and unpaid dividends are paid in full.
On November 13, 2015, the Company entered into
a Eleventh Amendment to the Amended and Restated Credit Agreement (the “Eleventh Amendment”). The Eleventh Amendment
reflects the following changes: (i) waived certain provisions of the Credit Agreement, (ii) suspend certain hedging requirements,
and (iii) to make certain other amendments to the Credit Agreement.
Our Business
Our principal strategy is to acquire, develop,
explore and produce domestic onshore oil and natural gas properties. Our business activities are currently focused in Kansas, Colorado,
Nebraska, and Texas.
Our total net proved oil and gas reserves
as of December 31, 2015 were 2.6 million barrels of oil equivalents (BOE), of which 59.4% was oil. Of the 2.6
million BOE of total proved reserves, approximately 39.0% are classified as proved developed producing, approximately
32.9% are classified as proved developed non-producing, and approximately 28.1% are classified as proved undeveloped.
The total PV10 (present value) of our
proved reserves as of December 31, 2015 was approximately $8.8 million. “PV10” means the estimated future
gross revenue to be generated from the production of proved reserves, net of estimated production and future development and
abandonment costs after giving consideration of salvage value there were no material abandonment costs included in future
development costs, using prices and costs in effect at the determination date, before income taxes, and without giving
effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance
with the guidelines of the SEC. PV10 is a non-GAAP financial measure and generally differs from the standardized measure of
discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the
effects of income taxes on future net revenues. See “Management’s Discussion and Analysis of Financial Condition
and Results of Operations-Reserves” page 36, for a reconciliation to the comparable GAAP financial measure.
Except where noted, the discussion regarding
our business in this Annual Report on Form 10-K is as of December 31, 2015.
Our Colorado Properties
The table below summarizes our current Colorado
and Nebraska acreage by project name as of December 31, 2015.
Project Name
|
|
Developed Acreage
(1)
|
|
|
Undeveloped Acreage
|
|
|
Total Acreage
|
|
|
|
Gross
|
|
|
Net
(2)
|
|
|
Gross
|
|
|
Net
(2)
|
|
|
Gross
|
|
|
Net
(2)
|
|
Adena
|
|
|
18,280
|
|
|
|
18,280
|
|
|
|
-
|
|
|
|
-
|
|
|
|
18,280
|
|
|
|
18,280
|
|
Hereford
|
|
|
-
|
|
|
|
-
|
|
|
|
3,400
|
|
|
|
3,400
|
|
|
|
3,400
|
|
|
|
3,400
|
|
Seven Cross
|
|
|
640
|
|
|
|
544
|
|
|
|
-
|
|
|
|
-
|
|
|
|
640
|
|
|
|
544
|
|
Niobrara - Colorado
(3)
|
|
|
21,773
|
|
|
|
21,010
|
|
|
|
25,176
|
|
|
|
22,929
|
|
|
|
46,949
|
|
|
|
43,939
|
|
Niobrara - Nebraska
|
|
|
-
|
|
|
|
-
|
|
|
|
9,516
|
|
|
|
9,356
|
|
|
|
9,516
|
|
|
|
9,356
|
|
Total
|
|
|
40,693
|
|
|
|
39,834
|
|
|
|
38,092
|
|
|
|
35,685
|
|
|
|
78,785
|
|
|
|
75,519
|
|
|
(1)
|
Developed acreage includes all acreage that was held by production as of December 31, 2015.
|
|
(2)
|
Net acreage is based on our net working interest as of December 31, 2015.
|
|
(3)
|
Developed acreage includes 8,372 net acres with rights limited to depths below the Niobrara formation.
|
Adena Field Project
The Adena Field Project is located in the
Denver-Julesburg (“D-J”) Basin in Morgan County, Colorado, where we owned a 100% working interest in 18,280 gross acres
as of December 31, 2015. Our acreage position covers the majority of Adena Field, which is the third largest oil field ever discovered
in Colorado behind Rangely Field and Wattenberg Field. Adena Field has cumulatively produced 75 million barrels of oil and 125
billion cubic feet of natural gas since its discovery in the early 1950s. Our acreage in this project is currently held-by-production
(see “Glossary” on page 15 for definition of held-by-production). The majority of the producing wells in Adena Field
were temporarily abandoned or shut-in during the mid-1980’s when oil prices collapsed, and a relatively small number of wells
have been produced since that time.
Approximately 111 wells on our acreage are
currently shut-in or temporarily abandoned. Our current understanding of the field indicates that most of the remaining 97 shut-in
oil wells are candidates for reactivation, recompletion or use in a larger scale EOR project. The same is true for the remaining
14 shut-in injection wells. We have a significant EOR project study under way at the present time and have begun field sampling
and EOR flood modeling for each project. We intend to reactivate vintage secondary recovery injection wells simultaneously with
the reactivation and/or recompletion of producer wells. Recompletions and reactivations are expected to cost approximately $200,000
to $250,000 per well and are expected to result in stabilized production rates of approximately 10 barrels of oil per day. We have
also identified a number of wells on our acreage that are prospective for natural gas production from the J-Sand and D-Sand formations.
As of December 31, 2015, the Adena
Field Project was producing approximately 100 gross barrels of oil per day from 20 J-Sand wells and 10 D-Sand wells at a
depth of approximately 5,500 feet. One J sand gas producer was temporarily shut-in because of low natural gas prices and due
to reservoir management practices. Multiple wells are off production because they require maintenance work; however,
we have delayed maintenance expenditures due to low commodity prices. We intend to pursue our reactivation and recompletion
strategy once oil prices recover.
Our working interest in our Adena Field Project
is subject to a 30% reversionary working interest that will be assigned to an unrelated third party after payout of all acquisition,
operating, development, and financing costs including interest (approximately $33 million at December 31, 2015).
Niobrara – Colorado & Nebraska
Our Niobrara Project is located in the northeastern
portion of the D-J Basin, where we owned a 100% working interest in approximately 56,465 gross acres as of December 31, 2015. Our
acreage is located in Phillips and Sedgwick Counties, Colorado, and Perkins County, Nebraska.
Approximately 21,000 acres in this project are
held by production and leases on approximately 17,500 acres expire after 2016. As of December 31, 2015, we owned a 100% working
interest in 24 Niobrara gas wells and we owned approximately a 6% overriding royalty interest in 180 Niobrara gas wells that are operated
by Atlas Resources, LLC. All of these wells are located in Amherst Field in Phillips and Sedgwick Counties, Colorado. As of December
31, 2015, we produced approximately 125 net mcf of natural gas per day from the Niobrara formation at a depth of approximately
2,500 feet.
Our existing Niobrara acreage was high-graded
based on structural features identified through analysis of 114 miles of 2D and 165 square miles (105,000 acres) of 3D seismic
data on our original position of 330,000 net acres. We have identified more than 150 highly-ranked Niobrara drilling locations
on our acreage based on 3D seismic analysis, which has historically yielded success rates of approximately 90% in this play. Our
acreage is well situated with direct access to the Cheyenne Hub market in immediate proximity to the 1,679-mile Rocky Mountain
Express pipeline and the 436-mile Trailblazer pipeline.
In 2015, we consummated a joint venture
with third party industry partners to drill exploration wells targeting deeper potential pay zones in our Niobrara project acreage.
Per the terms of the joint venture agreement, our industry partners agreed to pay 100% of drilling and completion costs of the
first four exploration wells drilled in the project area. We drilled the first two exploration wells during the fourth quarter
2015, and we elected to plug and abandon those wells. Future test wells are not planned at this time.
DJ Basin Resource Play Exposure
Other operators in the DJ basin have recently
permitted, drilled and tested numerous wells on trend with our Niobrara Project acreage and our Adena Field Project acreage. These
operators are targeting oil production from conventional reservoirs and unconventional resource plays in Permian and Pennsylvanian
aged carbonates and shales. These plays are in the early stages of exploration and development, and widespread economic success
has not yet been established. We continue to monitor these exploration efforts closely and we currently own and control all depths
that are prospective for these plays under all of our current acreage position.
Our Kansas Properties
The table below summarizes our current Kansas
acreage by project name as of December 31, 2015.
Project Name
|
|
Developed Acreage
(1)
|
|
|
Undeveloped Acreage
|
|
|
Total Acreage
|
|
|
|
Gross
|
|
|
Net
(2)
|
|
|
Gross
|
|
|
Net
(2)
|
|
|
Gross
|
|
|
Net
(2)
|
|
Mississippian Project
|
|
|
3,880
|
|
|
|
3,492
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3,880
|
|
|
|
3,880
|
|
Other
|
|
|
584
|
|
|
|
146
|
|
|
|
-
|
|
|
|
-
|
|
|
|
584
|
|
|
|
146
|
|
Total
|
|
|
4,464
|
|
|
|
3,638
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4,464
|
|
|
|
3,638
|
|
|
(1)
|
Developed acreage includes all acreage that was held by production as of December 31, 2015.
|
|
(2)
|
Net acreage is based on our net working interest as of December 31, 2015.
|
Mississippian Project
Our Mississippian Project is located in Woodson
and Greenwood Counties in Southeast Kansas, where we owned a 90% working interest in 3,880 gross acres. Approximately 73.5% of
the gross leased acres in this project are currently held-by-production.
As of December 31, 2015, our Mississippian
Project was producing approximately 125 gross barrels of oil per day from the Mississippian formation at a depth of approximately
1,700 feet.
Cherokee Project
Our Cherokee Project is located in Miami and
Franklin Counties in Eastern Kansas, where we owned an average working interest of 86% in 10,252 gross acres as of December 31,
2014.
On August 12, 2015, EnerJex
Resources, Inc., through its subsidiaries, EnerJex Kansas, Inc., and Working Interest, LLC, sold the Cherokee Project for approximately $2.8 million to Haas Petroleum, LLC, BAM Petroleum, LLC and
MorMeg, LLC. The effective date of the sale was July 1, 2015.
Our Texas Properties
The table below summarizes our current Texas
acreage by project name as of December 31, 2015.
Project Name
|
|
Developed Acreage
(1)
|
|
|
Undeveloped Acreage
|
|
|
Total Acreage
|
|
|
|
Gross
|
|
|
Net
(2)
|
|
|
Gross
|
|
|
Net
(2)
|
|
|
Gross
|
|
|
Net
(2)
|
|
El Toro Project
|
|
|
458
|
|
|
|
275
|
|
|
|
-
|
|
|
|
-
|
|
|
|
458
|
|
|
|
275
|
|
Total
|
|
|
458
|
|
|
|
275
|
|
|
|
-
|
|
|
|
-
|
|
|
|
458
|
|
|
|
275
|
|
|
(1)
|
Developed acreage includes all acreage that was held by production as of December 31, 2015.
|
|
(2)
|
Net acreage is based on our net working interest as of December 31, 2015.
|
El Toro
Project
Our El Toro Project is located in Atascosa
and Frio Counties in South Texas. As of December 31, 2015, we owned a 60% working interest in 458 gross acres. As of December 31,
2015, this project was producing approximately 10 gross barrels of oil per day from the Olmos formation at a depth of approximately
4,500 feet.
Our Business Strategy
Our principal strategy focuses on the acquisition
and development of oil and gas properties that have low production decline rates and offer drilling opportunities with low risk
profiles. Our oil and gas operations are in Kansas, Colorado, Nebraska, and Texas. The principal elements of our business strategy
are:
|
·
|
Develop Our Existing Properties.
Creating production, cash flow, and reserve growth by developing our inventory of hundreds of drilling locations that we have identified on our existing properties.
|
|
·
|
Maximize Operational Control.
We seek to operate and maintain a substantial working interest in the majority of our properties. We believe the ability to control our drilling inventory will provide us with the opportunity to more efficiently allocate capital, manage resources, control operating and development costs, and utilize our experience and knowledge of oil and gas field technologies.
|
|
·
|
Pursue Selective Acquisitions and Joint Ventures.
We believe our local presence in Kansas, Colorado, Nebraska, and Texas makes us well-positioned to pursue selected acquisitions and joint venture arrangements.
|
|
·
|
Reduce Unit Costs Through Economies of Scale and Efficient Operations.
As we increase our oil and gas production and develop our existing properties, we expect that our unit cost structure will benefit from economies of scale. In particular, we anticipate reducing unit costs by greater utilization of our existing infrastructure over a larger number of wells.
|
Our future financial results will continue
to depend on:
|
·
|
the market price for oil, gas and natural gas liquids;
|
|
|
|
|
·
|
our ability to preserve sufficient working capital and maintain access to capital resources;
|
|
·
|
our ability to cost effectively manage our operations;
|
|
·
|
our ability to source and evaluate potential projects;
|
|
·
|
our ability to discover and exploit commercial quantities of oil and gas;
|
|
·
|
our ability to implement our exploration and development program.
|
We cannot guarantee that we will succeed in
any of these respects. Further, we cannot know if the price of crude oil and natural gas prevailing at the time of production will
be at a level allowing for profitable production, or that we will be able to obtain additional funding at terms favorable to us
to increase our capital resources. A detailed description of these and other risks that could materially impact our actual results
is in “Risk Factors” under ITEM 1A.
Drilling Activity
The following table sets
forth the results of our drilling activities, including both oil and gas production wells and water injection wells that were
drilled and completed during the year ended December 31, 2015 and the year ended December 31, 2014.
Drilling Activity
|
|
|
Gross Wells
|
|
|
Net Wells
(1)
|
|
Fiscal Year
|
|
Total
|
|
|
Successful
|
|
|
Dry
|
|
|
Total
|
|
|
Successful
|
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 - Development
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
2015 - Exploratory
|
|
|
2
|
|
|
|
-
|
|
|
|
2
|
|
|
|
1.0
|
|
|
|
-
|
|
|
|
1.0
|
|
2014 - Development
|
|
|
52
|
|
|
|
51
|
|
|
|
1
|
|
|
|
41.0
|
|
|
|
40.1
|
|
|
|
0.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 - Recompletion
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
2014 - Recompletion
|
|
|
19
|
|
|
|
19
|
|
|
|
-
|
|
|
|
19
|
|
|
|
19
|
|
|
|
-
|
|
|
(1)
|
Net wells are based on our net working interest at the end of each respective year.
|
Net Production, Average Sales Price and Average Production and
Lifting Costs
The table below sets forth our net oil and gas
production (net of all royalties, overriding royalties and production due to others) for the years ended December 31, 2015 and
2014, the average sales prices, average production costs and direct lifting costs per unit of production.
|
|
Year ended December 31,
|
|
|
|
2015
|
|
|
2014
|
|
Net Production
|
|
|
|
|
|
|
|
|
Crude oil (bbl)
|
|
|
96,244
|
|
|
|
150,469
|
|
Natural gas liquids (bbl)
|
|
|
6,045
|
|
|
|
6,619
|
|
Natural gas (mcf)
|
|
|
188,408
|
|
|
|
318,226
|
|
|
|
|
|
|
|
|
|
|
Average Sales Prices
|
|
|
|
|
|
|
|
|
Crude oil (per bbl)
|
|
$
|
46.76
|
|
|
|
86.76
|
|
Natural gas liquids (per bbl)
|
|
$
|
4.01
|
|
|
|
30.65
|
|
Natural gas (per mcf)
|
|
$
|
1.88
|
|
|
|
3.25
|
|
|
|
|
|
|
|
|
|
|
Average Production Cost
(1)
per BOE
|
|
$
|
48.78
|
|
|
|
48.78
|
|
Average Lifting Costs
(2)
per BOE
|
|
$
|
31.99
|
|
|
|
31.99
|
|
|
(1)
|
Production costs include all operating expenses, depreciation, depletion and amortization, lease operating expenses (including price differentials) and all associated taxes. Impairment of oil and gas properties is not included in production costs.
|
|
(2)
|
Direct lifting costs do not include impairment expense or depreciation, depletion and amortization, but do include transportation costs, which are paid to our purchasers as a price differential.
|
Results of Oil and Gas Producing Activities
The following table shows the results of operations
from our oil and gas producing activities from the years ended December 31, 2015 and 2014. Results of operations from these activities
have been determined using historical revenues, production costs, depreciation, depletion and amortization of the capitalized costs
subject to amortization. General and administrative expenses and interest expense have been excluded from this determination.
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2015
|
|
|
2014
|
|
Production revenues
|
|
$
|
4,878,722
|
|
|
$
|
14,293,368
|
|
Production costs
|
|
|
(4,501,940
|
)
|
|
|
(6,762,248
|
)
|
Depreciation, depletion and amortization
|
|
|
(1,311,446
|
)
|
|
|
(3,259,442
|
)
|
Results of operations for producing activities
|
|
$
|
(934,664
|
)
|
|
$
|
4,271,678
|
|
Active Wells
The following table sets forth the number of
wells in which we owned a working interest that were actively producing oil and gas or actively injecting water as of December
31, 2015.
|
|
Active
|
|
Project
|
|
Gross
|
|
|
Net
(1)
|
|
Crude Oil
|
|
|
|
|
|
|
|
|
El Toro Project
|
|
|
12
|
|
|
|
7.2
|
|
Mississippian Project
|
|
|
231
|
|
|
|
207.9
|
|
Adena Field Project
|
|
|
51
|
|
|
|
51.0
|
|
Other
|
|
|
40
|
|
|
|
35.2
|
|
Total Oil
|
|
|
334
|
|
|
|
301.3
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
Niobrara Project
|
|
|
21
|
|
|
|
21.0
|
|
Other
|
|
|
36
|
|
|
|
3.2
|
|
Total Gas
|
|
|
57
|
|
|
|
24.2
|
|
|
(1)
|
Net wells are based on our net working interest as of December 31, 2015.
|
Reserves
Proved Reserves
The estimated total PV10 (present value) of
our proved reserves as of December 31, 2015 was $
8.8
million,
compared to $64.3 million as of December 31, 2014. Our total net proved oil and gas reserves as of December 31, 2015 were
2.6 million BOE (59% oil), compared to 4.4 million BOE (69% oil) as of December 31, 2014. Of the 2.6 million net BOE of total
proved reserves at December 31, 2015, approximately 39.0% are classified as proved developed producing, approximately 32.9% are
classified as proved developed non-producing, and approximately 28.1% are classified as proved undeveloped. See “Glossary”
on page 17 for our definition of PV10.
The estimated PV10 of the 2.6 million BOE is
set forth in the following table. The PV10 is calculated using an average net oil price of $50.28 per barrel, an average net natural
gas price of $2.58 per mcf and an average natural gas liquids price of $9.80 per barrel, and by applying an annual discount rate
of 10% to the forecasted future net cash flow.
In 2015 the Company invested approximately $250,000 in its oil and gas properties.
These reduced expenditures were primarily in response to extremely low commodity prices. The Company has $7.4 million of current
asset on hand, approximately $3.7 million of unrealized hedge gains and important infrastructure in Colorado completed which will
facilitate the exploitation and development of proved undeveloped reserves over the next five years. At year end the Company’s
review of proved undeveloped reserves revealed no instances of reserves that have not been developed within five years of their
initial recording as a proved undeveloped reserve. In addition it believes it has the financial wherewithal to develop all it’s
proved undeveloped reserves within the five year time frames required; utilizing its balance sheet, it borrowed $.5 million from
its bank in January 2015 and has the ability to joint venture any of its assets.
Summary of Proved Oil and Gas Reserves
December 31, 2015
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
Oil
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
Oil
|
|
|
|
|
|
|
Crude Oil
|
|
|
Liquids
|
|
|
Natural Gas
|
|
|
Equivalents
|
|
|
Crude Oil
|
|
|
Liquids
|
|
|
Natural Gas
|
|
|
Equivalents
|
|
|
PV 10
(2)
|
|
Proved Reserves Category
|
|
BBL’s
|
|
|
BBL’s
|
|
|
MCF’s
|
|
|
BOE’s
|
|
|
BBL’s
|
|
|
BBL’s
|
|
|
MCF’s
|
|
|
BOE’s
(1)
|
|
|
(before tax)
|
|
Proved, Developed
|
|
|
1,739,160
|
|
|
|
62,080
|
|
|
|
5,292,310
|
|
|
|
2,683,290
|
|
|
|
1,329,140
|
|
|
|
48,930
|
|
|
|
2,842,970
|
|
|
|
1,851,900
|
|
|
|
7,027,000
|
|
Proved, Undeveloped
|
|
|
196,860
|
|
|
|
-
|
|
|
|
4,176,000
|
|
|
|
892,860
|
|
|
|
152,610
|
|
|
|
-
|
|
|
|
3,422,170
|
|
|
|
722,970
|
|
|
|
1,743,000
|
|
Total Proved
|
|
|
1,936,020
|
|
|
|
62,080
|
|
|
|
9,468,310
|
|
|
|
3,576,150
|
|
|
|
1,481,740
|
|
|
|
48,930
|
|
|
|
6,265,140
|
|
|
|
2,574,860
|
|
|
|
8,770,000
|
|
|
(1)
|
Net BOE is based upon our net revenue interest
|
|
(2)
|
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Reserves” page 34 for a reconciliation to the comparable GAAP financial measure.
|
Oil and Gas Reserves Reported to Other Agencies
We did not file any estimates of total proved
net oil and gas reserves with, or include such information in reports to any federal authority or agency, other than the SEC, during
the year ended December 31, 2015.
Title to Properties
We believe that we have satisfactory title
to or rights in all of our producing properties. As is customary in the oil and gas industry, minimal investigation of title is
made at the time of acquisition of undeveloped properties. In most cases, we investigate title and obtain title opinions from counsel
or have title reviewed by professional landmen only when we acquire producing properties or before we begin drilling operations.
However, any acquisition of producing properties without obtaining title opinions is subject to a greater risk of title defects.
Our properties are subject to customary royalty
interests, liens under indebtedness, liens incident to operating agreements and liens for current taxes and other burdens, including
mineral encumbrances and restrictions. Further, our debt is secured by liens substantially on all of our assets. These burdens
have not materially interfered with the use of our properties in the operation of our business to date, though there can be no
assurance that such burdens will not materially impact our operations in the future
Sale
of Oil and Gas
We do not intend to refine our
oil production. We expect to sell all or most of our production to a small number of purchasers in a manner consistent
with industry practices at prevailing rates by means of long-term and short-term sales contracts, some of which may have
fixed price components. In 2015, we sold oil to ARM Energy Management LLC, Coffeyville Resources, Inc., Plains Marketing LP,
MV Purchasing, and Sunoco Logistics, Inc. on a month-to-month basis (i.e., without a long-term contract). We sold our natural gas to
United Energy Trading on a month-to-month basis and Western Operating Company under a long-term contract. Under current
conditions, we should be able to find other purchasers, if needed. All of our produced oil is held in tank batteries. Each
respective purchaser picks up the oil from our tank batteries and transports it by truck to refineries. In addition, our
Board of Directors has implemented a crude oil and gas hedging strategy that will allow management to hedge the majority of
our net production in an effort to mitigate our exposure to changing oil and natural gas prices in the intermediate term. We
have an ISDA master agreement and a deferred premium put options with BP through December 31, 2016.
Secondary Recovery and Other Production
Enhancement Strategies
When an oil field is first produced, the oil
typically is recovered as a result of natural pressure within the producing formation, often assisted by pumps of various types.
The only natural force present to move the crude oil to the wellbore is the pressure differential between the higher pressure in
the formation and the lower pressure in the wellbore. At the same time, there are many factors that act to impede the flow of crude
oil, depending on the nature of the formation and fluid properties, such as pressure, permeability, viscosity and water saturation.
This stage of production is referred to as “primary production”, which typically only recovers 5% to 15% of the crude
oil originally in place in a producing formation.
Production from oil fields can often be enhanced
through the implementation of “secondary recovery”, also known as water flooding, which is a method in which water is
injected into the reservoir through injector wells in order to maintain or increase reservoir pressure and push oil to the adjacent
producing wellbores. We utilize water flooding as a secondary recovery technique for the majority of our oil properties in Kansas,
even in the early stages of production and we use a secondary recovery technique in parts of the Adena Field Project in Colorado.
As a water flood matures over time, the fluid
produced contains increasing amounts of water and decreasing amounts of oil. Surface equipment is used to separate the produced
oil from water, with the oil going to holding tanks for sale and the water being re-injected into the oil reservoir.
In addition, we may utilize 3D seismic analysis,
horizontal drilling, and other technologies and production techniques to improve drilling results and oil recovery, and to ultimately
enhance our production and returns. We also believe use of such technologies and production techniques in exploring for, developing,
and exploiting oil properties will help us reduce drilling risks, lower finding costs and provide for more efficient production
of oil from our properties.
Markets and Marketing
The oil and gas industry has experienced dramatic
price volatility in recent years. As a commodity, global oil prices respond to macro-economic factors affecting supply and demand.
In particular, world oil prices have risen and fallen in response to political unrest and supply uncertainty in the Middle East,
and changing demand for energy in rapidly emerging market economies, notably India and China. North American prospects became more
attractive as oil prices rose worldwide. Escalating conflicts in the Middle East and the ability of OPEC to control supply and
pricing are some of the factors impacting the availability of global supply. As a commodity, natural gas prices respond mainly
to regional supply and demand imbalances. Factors that affect the supply side include production of natural gas, levels of natural
gas imports and fluctuations in underground storage. Factors that affect the demand side include peak demand brought on by
winter heating and summer cooling requirements and increasing demand from the petrochemical industry for their produced products
such as plastics, fertilizers, paints, soaps etc. The costs of steel and other products used to construct drilling rigs and pipeline
infrastructure, as well as, drilling and well-servicing rig rates, are impacted by the commodity price volatility.
Our market is affected by many factors beyond
our control, such as the availability of other domestic production, commodity prices, the proximity and capacity of oil and gas
pipelines, and general fluctuations of global and domestic supply and demand. In 2015 had month-to-month sales contracts with ARM
Energy Management LLC, Coffeyville Resources, Inc., Plains Marketing LP, MV Purchasing, Sunoco Logistics, Inc., United Energy
Trading and Western Operating Company and we do not anticipate difficulty in finding additional sales opportunities, as and when
needed.
Oil and gas sales prices are negotiated based
on factors such as the spot price or posted price for oil and gas, price regulations, regional price variations, hydrocarbon quality,
distances from wells to pipelines, well pressure, and estimated reserves. Many of these factors are outside our control. Oil and
gas prices have historically experienced high volatility, related in part to ever-changing perceptions within the industry of future
supply and demand.
Competition
The oil and gas industry is intensely competitive
and we must compete against larger companies that may have greater financial and technical resources than we do and substantially
more experience in our industry. These competitive advantages may better enable our competitors to sustain the impact of higher
exploration and production costs, oil and gas price volatility, productivity variances between properties, overall industry cycles
and other factors related to our industry. Their advantage may also negatively impact our ability to acquire prospective properties,
develop reserves, attract and retain quality personnel and raise capital.
Research and Development Activities
We have not spent a material amount of time
or money on research and development activities in the last two years.
Governmental Regulations
Our oil and gas exploration, production and
related operations, when developed, are subject to extensive rules and regulations promulgated by federal, state, tribal and local
authorities and agencies that impose requirements relating to the exploration and production of oil and natural gas. For example,
laws and regulations often address conservation matters, including provisions for the unitization or pooling of oil and gas properties,
the spacing, plugging and abandonment of wells, rates of production, water discharge, prevention of waste, and other matters. Prior
to drilling, we are often required to obtain permits for drilling operations, drilling bonds and file reports concerning operations.
Failure to comply with any such rules and regulations can result in substantial penalties. Moreover, laws and regulations may place
burdens from previous operations on current lease owners that can be significant.
The public attention on the production of oil
and gas will most likely increase the regulatory burden on our industry and increase the cost of doing business, which may affect
our profitability. Although we believe we are currently in substantial compliance with all applicable laws and regulations, because
such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying
with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material
adverse effect on our financial condition and results of operations.
The price we may receive from the sale of oil
and gas will be affected by the cost of transporting products to markets. Effective January 1, 1995, FERC implemented regulations
establishing an indexing system for transportation rates for oil and gas pipelines, which, generally, would index such rates to
inflation, subject to certain conditions and limitations. We are not able to predict with certainty the effect, if any, of these
regulations on our intended operations. However, the regulations may increase transportation costs or reduce well head prices for
oil and natural gas.
Environmental Matters
Our operations and properties are subject to
extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation,
storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health.
The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely
continue.
These laws and regulations may:
|
·
|
require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;
|
|
·
|
limit or prohibit construction, drilling and other activities on certain lands; and
|
|
·
|
impose substantial liabilities for pollution resulting from its operations, or due to previous operations conducted on any leased lands.
|
The permits required for our operations may
be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their
regulations, and violations are subject to fines or injunctions, or both. In the opinion of management, we are in substantial compliance
with current applicable environmental laws and regulations, and have no material commitments for capital expenditures to comply
with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations
thereof could have a significant impact on us, as well as the oil and gas industry in general.
The Comprehensive Environmental, Response,
Compensation, and Liability Act, as amended (“CERCLA”), and comparable state statutes impose strict, joint and several
liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances”
found at such sites. It is not uncommon for the neighboring land owners and other third parties to file claims for personal injury
and property damage allegedly caused by the hazardous substances released into the environment. The Federal Resource Conservation
and Recovery Act, as amended (“RCRA”), and comparable state statutes govern the disposal of “solid waste” and
“hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA
currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose
clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil and
gas field wastes as “non-hazardous”, such exploration and production wastes could be reclassified as hazardous wastes
thereby making such wastes subject to more stringent handling and disposal requirements.
The Federal Water Pollution Control Act of
1972, as amended (“Clean Water Act”), and analogous state laws impose restrictions and controls on the discharge of pollutants
into federal and state waters. These laws also regulate the discharge of storm water in process areas. Pursuant to these laws and
regulations, we are required to obtain and maintain approvals or permits for the discharge of wastewater and storm water and develop
and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans”, in connection with
on-site storage of greater than threshold quantities of oil and gas. The EPA issued revised SPCC rules in July 2002 whereby SPCC
plans are subject to more rigorous review and certification procedures. We believe that our operations are in substantial compliance
with applicable Clean Water Act and analogous state requirements, including those relating to wastewater and storm water discharges
and SPCC plans.
The Endangered Species Act, as amended (“ESA”),
seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify
the critical habitat of such species. Under ESA, exploration and production operations, as well as actions by federal agencies,
may not significantly impair or jeopardize the species or its habitat. ESA provides for criminal penalties for willful violations
of the Act. Other statutes that provide protection to animal and plant species and that may apply to our operations include, but
are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory
Bird Treaty Act and the National Historic Preservation Act. Although we believe that our operations will be in substantial compliance
with such statutes, any change in these statutes or any reclassification of a species as endangered could subject us to significant
expenses to modify our operations or could force us to discontinue certain operations altogether.
Personnel
We currently have 16 full-time employees, including
field personnel. As production and drilling activities increase or decrease, we may have to continue to adjust our technical, operational
and administrative personnel as appropriate. We are using and will continue to use independent consultants and contractors to perform
various professional services, particularly in the area of land services, reservoir engineering, geology, drilling, water hauling,
pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment. We believe
that this use of third-party service providers may enhance our ability to contain operating and general expenses, and capital costs.
Facilities
Executive offices are maintained at 4040 Broadway,
Suite 508, San Antonio, Texas 78209 under a lease expiring November 2017. We also have a field office located at 165 South
Union Blvd, Suite 410, Lakewood Colorado 80228, under a lease which expires October 2019.
GLOSSARY
Term
|
|
Definition
|
|
|
|
Barrel (Bbl)
|
|
The standard unit of measurement of liquids in the petroleum industry, it contains 42 U.S. standard gallons. Abbreviated to “bbl”.
|
|
|
|
Basin
|
|
A depression in the crust of the Earth, caused by plate tectonic activity and subsidence, in which sediments accumulate. Sedimentary basins vary from bowl-shaped to elongated troughs. Basins can be bounded by faults. Rift basins are commonly symmetrical; basins along continental margins tend to be asymmetrical. If rich hydrocarbon source rocks occur in combination with appropriate depth and duration of burial, then a petroleum system can develop within the basin.
|
|
|
|
BOE
|
|
Abbreviation for a barrel of oil equivalent and is a term used to summarize the amount of energy that is equivalent to the amount of energy found in a barrel of crude oil. On a BTU basis 6,000 cubic feet of natural gas is the energy equivalent to one barrel of crude oil. A conversion ratio of 6:1 is used to convert natural gas measured in thousands of cubic feet into an equivalent barrel of oil.
|
|
|
|
BOPD
|
|
Abbreviation for barrels of oil per day, a common unit of measurement for volume of crude oil. The volume of a barrel is equivalent to 42 U.S. standard gallons.
|
|
|
|
Carried Working Interest
|
|
The owner of this type of working interest in the drilling of a well incurs no capital contribution requirement for drilling or completion costs associated with a well and, if specified in the particular contract, may not incur capital contribution requirements beyond the completion of the well.
|
|
|
|
Completion/Completing
|
|
The activities and methods of preparing a well for the production of oil and gas or for other purposes such as injection.
|
|
|
|
Development
|
|
The phase in which a proven oil or natural gas field is brought into production by drilling development wells.
|
|
|
|
Development Drilling
|
|
Wells drilled during the Development phase.
|
|
|
|
Division Order
|
|
A directive signed by all owners verifying to the purchaser or operator of a well the decimal interest of production owned by the royalty owner and other working interest owners. The Division Order generally includes the decimal interest, a legal description of the property, the operator’s name, and several legal agreements associated with the process. Completion of this step generally precedes placing the royalty owner or working interest owner on pay status to begin receiving revenue payments.
|
|
|
|
Drilling
|
|
Act of boring a hole through which oil and natural gas may be produced.
|
|
|
|
Dry Wells
|
|
A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
|
|
|
|
Exploration
|
|
The phase of operations which covers the search for oil and gas generally in unproven or semi-proven territory.
|
Exploratory Drilling
|
|
Drilling of a relatively high percentage of properties which are unproven.
|
|
|
|
Farm Out
|
|
An arrangement whereby the owner of a lease assigns all or some portion of the lease or licenses to another company for undertaking exploration or development activity.
|
|
|
|
Fixed Price Swap
|
|
A derivative instrument that exchanges or “swaps” the “floating” or daily price of a specified volume of oil or natural gas over a specified period, for a fixed price for the specified volume over the same period (typically three months or longer).
|
|
|
|
Gross Acre
|
|
The number of acres in which the Company owns any working interest.
|
|
|
|
Gross Producing Well
|
|
A well in which a working interest is owned and is producing oil or gas. The number of gross producing wells is the total number of wells producing oil or gas in which a working interest is owned.
|
|
|
|
Gross Well
|
|
A well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.
|
|
|
|
Held-By-Production (HBP)
|
|
Refers to an oil and gas property under lease, in which the lease continues to be in force, because of production from the property.
|
|
|
|
Horizontal drilling
|
|
A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then turned and drilled horizontally. Horizontal drilling allows the wellbore to follow the desired formation.
|
|
|
|
In-Fill Wells
|
|
In-fill wells refers to wells drilled between established producing wells; a drilling program to reduce the spacing between wells in order to increase production and recovery of in-place hydrocarbons.
|
|
|
|
Oil and Gas Lease
|
|
A legal instrument executed by a mineral owner granting the right to another to explore, drill, and produce subsurface oil and gas. An oil and gas lease embodies the legal rights, privileges and duties pertaining to the lessor and lessee.
|
|
|
|
Lifting Costs
|
|
The expenses of producing oil and gas from a well. Lifting costs are the operating costs of the wells including the gathering and separating equipment. Lifting costs do not include the costs of drilling and completing the wells or transporting the oil and gas.
|
|
|
|
MCF
|
|
An abbreviation for one thousand cubic feet of natural gas.
|
|
|
|
Net Acres
|
|
Determined by multiplying gross acres by the working interest that the Company owns in such acres.
|
|
|
|
Net Producing Wells
|
|
The number of producing wells multiplied by the working interest in such wells.
|
|
|
|
Net Revenue Interest
|
|
A share of production revenues after all royalties, overriding royalties and other non-operating interests have been taken out of production for a well(s).
|
|
|
|
Operator
|
|
A person, acting for itself, or as an agent for others, designated to conduct the operations on its or the joint interest owners’ behalf.
|
Overriding Royalty
|
|
Ownership in a percentage of production or production revenues, free of the cost of production, created by the lessee, company and/or working interest owner and paid by the lessee, company and/or working interest owner out of revenue from the well.
|
|
|
|
Probable Reserves
|
|
Probable reserves are 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.
|
|
|
|
Proved Developed Reserves
|
|
Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. This definition of proved developed reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a) (2-4) of Regulation S-X.
|
|
|
|
Proved Developed Non-Producing
|
|
Proved developed reserves expected to be recovered from zones behind casings in existing wells or from future production increases resulting from the effects of water flood operations.
|
|
|
|
Proved Reserves
|
|
Proved reserves are estimated quantities of crude oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic, 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.
|
|
|
|
Proved Undeveloped Reserves
|
|
Proved undeveloped reserves are the portion of proved reserves which can be expected to be recovered from new wells on undrilled proved acreage, or from existing wells where a relatively major expenditure is required for completion. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a) (2-4) of Regulation S-X.
|
|
|
|
PV10
|
|
PV10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV10 is a non-GAAP financial measure. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Reserves” on page 33 for a reconciliation to the comparable GAAP financial measure.
|
|
|
|
Reactivation
|
|
After the initial completion of a well, the action and techniques of reentering the well and redoing or repairing the original completion to restore the well’s productivity.
|
|
|
|
Recompletion
|
|
Completion of an existing well for production from one formation or reservoir to another formation or reservoir that exists behind casing of the same well.
|
|
|
|
Reservoir
|
|
The underground rock formation where oil and gas has accumulated. It consists of a porous rock to hold the oil and gas, and a cap rock that prevents its escape.
|
Secondary Recovery
|
|
The stage of hydrocarbon production during which an external fluid such as water or natural gas is injected into the reservoir through injection wells located in rock that has fluid communication with production wells. The purpose of secondary recovery is to maintain reservoir pressure and to displace hydrocarbons toward the wellbore. The most common secondary recovery techniques are natural gas injection and water flooding. Normally, natural gas is injected into the natural gas cap and water is injected into the production zone to sweep oil and gas from the reservoir. A pressure-maintenance program can begin during the primary recovery stage, but it is a form of enhanced recovery.
|
|
|
|
Stock Tank Barrel or STB
|
|
A stock tank barrel of oil and gas is the equivalent of 42 U.S. Gallons at 60 degrees Fahrenheit.
|
|
|
|
Undeveloped Acreage
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Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.
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Unitize, Unitization
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When owners of oil and gas reservoir pool their individual interests in return for an interest in the overall unit.
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Water flood
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The injection of water into an oil and gas reservoir to “push” additional oil and gas out of the reservoir rock and into the wellbores of producing wells. Typically a secondary recovery process.
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Water Injection Wells
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A well in which fluids are injected rather than produced, the primary objective typically being to maintain or increase reservoir pressure, often pursuant to a water flood.
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Water Supply Wells
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A well in which fluids are being produced for use in a water injection well.
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Wellbore
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A borehole; the hole drilled by the bit. A wellbore may have casing in it or it may be open (uncased); or part of it may be cased, and part of it may be open. Also called a borehole or hole.
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Working Interest
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An interest in an oil and gas lease entitling the owner to receive a specified percentage of the proceeds of the sale of oil and gas production or a percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil and gas.
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ITEM 1A. RISK FACTORS.
In the course of conducting our business operations,
we are exposed to a variety of risks that are inherent to the oil and gas industry. The following discusses some of the key inherent
risk factors that could affect our business and operations. Other factors besides those discussed below or elsewhere in this report
also could adversely affect our business and operations, and these risk factors should not be considered a complete list of potential
risks that may affect us.
Risks Related to Recent Developments
Our 2015 oil and gas reserve report shows
a material decline in our estimated reserves, which will have adverse implications to our business.
Our 2015 oil and gas reserve
report shows a material decline in our estimated reserves. There are numerous uncertainties inherent in estimating quantities of
proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures, including
many factors beyond our control. For example, estimates of quantities of proved reserves and their PV10 value are affected by changes
in crude oil and gas prices, because estimates are based on prevailing prices at the time of their determination. Further, reserve
engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in any
exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological
interpretation and judgment. As a result, estimates made by different engineers often vary from one another.
The reduction in our reserve
estimates is likely to change the schedule of future production and development drilling that was contemplated in our 2014 and
2013 reserve reports. Reserve estimates are generally different, and often materially so, from the quantities of oil and natural
gas that are ultimately recovered. Furthermore, estimates of quantities of proved reserves and their PV10 value may be affected
by changes in crude oil and gas prices because the Company’s estimates are based on prevailing prices at the time of their
determination.
Due to our substantial
liquidity concerns, we may be unable to continue as a going concern.
The report of our independent registered
public accounting firm that accompanies our audited consolidated financial statements for the year ended December 31, 2015 contains
an explanatory paragraph regarding the substantial doubt about our ability to continue as a going concern.
Our existing and future debt agreements
could create issues as principal and interest payments become due and the debt matures that will threaten our ability to continue
as a going concern. On April 1, 2016 we informed our lender that we would cease making our mandatory monthly borrowing
base reduction payments, and we did not make the required April 1, 2016 payment, putting us in default. On April 6, 2016, we made
our mandatory quarterly interest payment, and on April 7, 2016 we entered into a Forbearance Agreement whereby our lender agreed
to not exercise remedies and rights afforded it under our credit agreement for 30 days. If after such 30-day period we fail to
satisfy our obligations with respect to our indebtedness or fail to comply with the financial and other restrictive covenants contained
in the credit agreement governing our indebtedness, an event of default could result, which would permit acceleration of such debt
and which could result in an event of default under and an acceleration of our other debt and would permit our lender to foreclose
on any of our assets securing such debt. Any accelerated debt would become immediately due and payable. There is no assurance that
our search for strategic alternatives or any particular actions with respect to refinancing existing indebtedness, extending the
maturity of existing indebtedness or curing potential defaults in our existing and future debt agreements will be sufficient. The
uncertainty associated with our ability to repay our outstanding debt obligations as they become due raises substantial doubt about
our ability to continue as a going concern.
Our substantial indebtedness and
liquidity issues may impact our business, financial condition and operations.
Due to our substantial indebtedness, liquidity
issues and the potential for restructuring transactions, there is risk that, among other things:
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it may become more difficult to retain, attract or replace key employees;
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employees could be distracted from performance of their duties or attracted to other career opportunities; and
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our suppliers, hedge counterparties, vendors and service providers could renegotiate the terms of our arrangements, terminate
their relationship with us or require financial assurances from us
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The occurrence of certain of these events
has already negatively affected our business and may continue to have a material adverse effect on our business, results of operations
and financial condition.
Our maximum borrowings
under our credit facility are subject to reduction based upon a borrowing base calculation, which is re-determined using updated
reserve reports. Because our 2015 reserve report shows a material reduction in reserves as discussed above, our borrowing base
will likely be similarly reduced. Such a reduction would increase the amount we are overdrawn on our credit facility and could
negatively impact waivers granted us for non-compliance with the financial covenants previously granted by our lenders.
Lenders may impose a plan requiring that we
reduce the amount of that overdraft. Any such plan may include an adjustment in the interest rate on our secured credit facilities
and a requirement increased amortizing payments. Any such plan would likely require, among other things, that we apply our net
cash flow to repayment of the principal of our secured credit facilities, limit our ability to pay our ordinary operating expenses
as they become due and limit our new production activities. All of those factors will adversely affect the results of our operations
and our stock price.
Current volatile market conditions and significant fluctuations
in energy prices may continue indefinitely, negatively affecting our business prospects and viability.
The oil and gas markets are very volatile,
and we cannot predict future oil and natural gas prices. Historically, oil and natural gas prices have been volatile and are subject
to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond
our control. Further declines in the price of oil and natural gas will have a material adverse effect on our planned operations
and financial condition. Additionally, the amount of any royalty payment we receive from the production of oil and gas from our
oil and gas interests will depend on numerous factors beyond our control.
We may continue to incur substantial write-downs of
the carrying value of our oil and gas properties, which would adversely impact our earnings.
We review the carrying value of our oil
and gas properties under the full cost method of accounting. Under the full cost method of accounting, the net book value of oil
and gas properties, less deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is (a)
the present value of future net revenues computed by applying current prices of oil & gas reserves (with consideration of price
changes only to the extent provided by contractual arrangements) to estimated future production of proved oil & gas reserves
as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred
in developing and producing the proved reserves computed using a discount factor of 10 percent and assuming continuation of existing
economic conditions
plus
(b) the cost of properties not being amortized
plus
(c) the lower of cost or estimated fair
value of unproven properties included in the costs being amortized
less
(d) income tax effects related to differences between
book and tax basis of properties. Future cash outflows associated with settling accrued retirement obligations are excluded from
the calculation. Estimated future cash flows are calculated using end-of-period costs and an un-weighted arithmetic average of
commodity prices in effect on the first day of each of the previous 12 months held flat for the life of the production, except
where prices are defined by contractual arrangements.
Any excess of the net book value of proved
oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional
DD&A in the statement of operations. The ceiling calculation is performed quarterly. For the year ended December 31, 2015 impairments
of $16,401,376, $11,421,613, $9,720,983 and $11,386,115 were record in the first, second, third and fourth quarters respectively.
For the year ended December 31, 2014 there were no impairments resulting from the quarterly ceiling tests.
Our stock price has recently declined below $1.00 per
share. If the average closing price of our common stock is less than $1.00 per share for a period of over 30 consecutive trading
days, the NYSE could delist our common stock.
The NYSE requires that the average closing
price of a listed company’s common stock not be less than $1.00 per share for a period of over 30 consecutive trading dates. Under
NYSE rules, a company can avoid delisting, if, during the six month period following receipt of the NYSE notice and on the last
trading day of any calendar month, a company’s common stock price per share and 30 trading-day average share price is at least
$1.00. During this six month period, a company’s common stock will continue to be traded on the NYSE, subject to compliance with
other continued listing requirements.
In the future, if our common stock ultimately
were to be delisted for any reason, it could negatively impact us by (i) reducing the liquidity and market price of our common
stock; (ii) reducing the number of investors willing to hold or acquire our common stock, which could negatively impact our ability
to raise equity financing; (iii) limiting our ability to use a registration statement to offer and sell freely tradeable securities,
thereby preventing us from accessing the public capital markets; and (iv) impairing our ability to provide equity incentives to
our employees.
Risks Associated with our Debt Financing
Significant and prolonged declines in commodity prices
have negatively impacted our borrowing base and our ability to borrow overall.
Our borrowing base, which is based on our
oil and gas reserves, is subject to review and adjustment on a semi-annual basis and other interim adjustments. In March our borrowing
base was reduced resulting in a “loan excess”. The “loan excess” was required to be eliminated through payment
of a portion of the loan via monthly reductions. Cash collateralization of Letters of Credit obligations; or adding properties
to the borrowing base sufficient to offset the “loan excess” may be required in the future. A reduction in
our borrowing base or the ability to borrow under our Credit Facility, combined with a reduction in cash flow from operations resulting
from a decline in oil and gas prices, would likely require us to further reduce our capital expenditures and our operating
activities.
Until we repay the full amount of our outstanding Credit
Facility, we may continue to have substantial indebtedness, which is secured by substantially all of our assets.
On December 31, 2015, we had $18,600,000
of bank loans outstanding. If we defaulted on our obligations with respect to the secured debt, the lenders may enforce their rights
as secured parties and we may lose all or a portion of our assets or be forced to materially reduce our business activities.
Our substantial indebtedness could make it more difficult
for us to fulfill our obligations under our Credit Facility and, therefore, adversely affect our business.
On November 13, 2015, the Company entered
into a Eleventh Amendment to Amended and Restated Credit Agreement (the “Eleventh Amendment”) with Texas Capital Bank.
In the Eleventh Amendment, the Bank (i) waived certain provisions of the Credit Agreement, (ii) suspend certain hedging requirements,
and (iii) to made certain other amendments to the Credit Agreement.
As of December 31, 2015, we had
total indebtedness of $18,600,000 under the Credit Facility and our borrowing base was $18,600,000. Our substantial
indebtedness, and the related interest expense, could have important consequences to us, including:
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our ability to borrow additional amounts for working capital, capital
expenditures, debt service requirements, execution of our business strategy, or other general corporate purposes;
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being forced to use cash flow to reduce our outstanding balance as
a result of an unfavorable borrowing base redetermination;
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our ability to use operating cash flow in other areas of our business
because we must dedicate a substantial portion of these funds to service our indebtedness;
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increasing our vulnerability to general adverse economic and industry
conditions;
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placing us at a competitive disadvantage as compared to our competitors
that have less leverage;
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our ability to capitalize on business opportunities and to react to
competitive pressures and changes in government regulation;
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our ability to, or increasing the cost of, refinancing our indebtedness;
and
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our ability to enter into marketing, hedging, optimization and trading
transactions by reducing the number of counterparties with whom we can enter into such transactions as well as the volume of those
transactions.
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The covenants in our Credit Facility
impose significant operating and financial restrictions on us.
The Credit Facility imposes significant
operating and financial restrictions on us. These restrictions limit our ability and the ability of our subsidiaries, among other
things, to:
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incur additional indebtedness and provide additional guarantees;
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pay dividends and make other restricted payments;
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create or permit certain liens;
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use the proceeds from the sales of our oil and gas properties;
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use the proceeds from the unwinding of certain financial hedges;
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engage in certain transactions with affiliates; and
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consolidate, merge, sell or transfer all or substantially all of our
assets or the assets of our subsidiaries.
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The Credit Facility also contains various
affirmative covenants with which we are required to comply. With the signing of the “Eleventh Amendment” on November
13, 2015 certain covenants were waived until December 31, 2016. With these covenants waived, we were incompliance with the affirmative
covenant provisions of the Credit Facility. We may be unable to comply with some or all of these covenants in the future. If we
do not comply with these covenants and are unable to obtain waivers from our lenders, we would be unable to make additional borrowings
under these facilities; our indebtedness under these agreements would be in default and repayment of debt could be accelerated
by our lenders. If our indebtedness is accelerated, we may not be able to repay our indebtedness or borrow sufficient
funds to refinance it. In addition, if we incur additional indebtedness in the future, we may be subject to additional covenants,
which may be more restrictive than those to which we are currently subject.
Risks Associated with our Industry
Oil and gas prices are volatile. Future price volatility
may negatively impact cash flows which could result in an inability to cover our operating and/or capital expenditures.
Our future revenues, profitability, future
growth and the carrying value of our properties depend substantially on the prices we realize for our oil and gas production. Our
realized prices may also affect the amount of cash flow available for operating and/or capital expenditures and our ability to
borrow and raise additional capital.
Oil and gas prices are subject to wide
fluctuations in response to relatively minor changes in or perceptions regarding supply and demand. Historically, the markets for
oil and gas have been volatile, and they are likely to continue to be volatile in the future. Among the factors that can cause
this volatility are:
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commodities speculators;
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local, national and worldwide economic conditions;
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worldwide or regional demand for energy, which is affected by economic
conditions;
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the domestic and foreign supply of oil and gas;
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acts of terrorism and war;
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domestic and foreign governmental regulations and taxation;
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political and economic conditions in oil and gas producing countries,
including those in the Middle East and South America;
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impact of the U.S. dollar exchange rates on oil and gas prices;
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the availability of refining capacity;
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actions of the Organization of Petroleum Exporting Countries, or OPEC,
and other state controlled oil and gas companies relating to oil and gas price and production controls; and
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the price and availability of other fuels.
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It is impossible to predict oil and gas
price movements with certainty. A drop in oil and gas prices may not only decrease our future revenues on a per unit basis but
also may reduce the amount of oil and gas that we can produce economically. A substantial or extended decline in oil and gas prices
would materially and adversely affect our future business enough to potentially force us to cease our business operations. In addition,
our reserves, financial condition, results of operations, liquidity and ability to finance and execute planned capital expenditures
will also suffer in such a price decline.
Declining economic conditions and worsening geopolitical
conditions could negatively impact our business.
Our operations are affected by local, national
and worldwide economic conditions. Markets in the United States and elsewhere have been experiencing volatility and disruption
for more than 5 years, due in part to the financial stresses affecting the liquidity of the banking system and the financial markets
generally. The consequences of a potential or prolonged recession may include a lower level of economic activity, decreasing
demand for petroleum products and uncertainty regarding energy prices and the capital and commodity markets.
In addition, actual and attempted terrorist
attacks in the United States, Middle East, Southeast Asia and Europe, and war or armed hostilities in the Middle East, the Persian
Gulf, North Africa, Iran, North Korea or elsewhere, or the fear of such events, could further exacerbate the volatility and disruption
to the financial markets and economies.
While the ultimate outcome and impact of the
current economic conditions cannot be predicted, a lower level of economic activity might result in a decline in energy consumption,
which may materially adversely affect the price of oil and gas, our revenues, liquidity and future growth. Instability
in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital.
The oil and natural gas business involves numerous uncertainties
and operating risks that can prevent us from realizing profits and can cause substantial losses.
Our development, exploitation and exploration activities may
be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover,
the successful drilling of a well does not ensure a profit on investment. A variety of factors, both geological and market-related,
can cause a well to become uneconomical or only marginally economical. In addition to their cost, unsuccessful wells can hurt our
efforts to replace reserves.
The oil and natural gas business involves a
variety of operating risks, including:
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unexpected operational events and/or conditions;
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reductions in oil and natural gas prices;
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limitations in the market for oil and natural gas;
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adverse weather conditions;
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facility or equipment malfunctions;
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title problems;
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oil and gas quality issues;
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pipe, casing, cement or pipeline failures;
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natural disasters;
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fires, explosions, blowouts, surface cratering, pollution and other risks or accidents;
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environmental hazards, such as oil spills, pipeline ruptures and discharges of toxic gases;
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compliance with environmental and other governmental requirements; and
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uncontrollable flows of oil or natural gas or well fluids.
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If we experience any of these problems, it
could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations.
We could also incur substantial losses as a result of:
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injury or loss of life;
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severe damage to and destruction of property, natural resources and equipment;
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pollution and other environmental damage;
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clean-up responsibilities;
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regulatory investigation and penalties;
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suspension of our operations; and
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repairs to resume operations.
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Because we use third-party drilling contractors
to drill our wells, we may not realize the full benefit of worker compensation laws in dealing with their employees. Our insurance
does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide
enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe
the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally
are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could impact
our operations enough to force us to cease our operations.
Approximately 28% of our total proved reserves as of December
31, 2015 consist of undeveloped reserves, and those reserves may not ultimately be developed or produced.
Our estimated total proved PV10 (present
value) before tax of reserves as of December 31, 2015 was $8.8 million, versus $64.3 million as of December 31, 2014. Of
the 2.6 million BOE of total proved reserves, approximately 39.0% are classified as proved developed producing, approximately
32.9% are classified as proved developed non-producing, and approximately 28.1% are classified as proved undeveloped.
Assuming we can obtain adequate capital
resources, we plan to develop and produce all of our proved reserves, but ultimately some of these reserves may not be developed
or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be produced in the time periods we
have planned, at the costs we have budgeted, or at all.
Because we face uncertainties in estimating proved recoverable
reserves, you should not place undue reliance on such reserve information.
Our reserve estimates and the future net
cash flows attributable to those reserves at December 31, 2015 were prepared by Cobb & Associates, Inc., an independent petroleum
consultant. There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from
such reserves, including factors beyond our control and the control of these independent consultants and engineers. Reserve engineering
is a subjective process of estimating underground accumulations of oil and gas that can be economically extracted, which cannot
be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to these reserves,
is a function of the available data, assumptions regarding future oil and gas prices, expenditures for future development and exploitation
activities, and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material
downward or upward revisions based upon production history, development and exploitation activities and oil and gas prices. Actual
future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of
cash flows from those reserves may vary significantly from the assumptions and estimates in our reserve reports. Any significant
variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable
quantities of oil and gas attributable to any particular group of properties, the classification of reserves based on risk of recovery,
and estimates of the future net cash flows. In addition, reserve engineers may make different estimates of reserves and cash
flows based on the same available data. The estimated quantities of proved reserves and the discounted present value of future
net cash flows attributable to those reserves included in this report were prepared by Cobb & Associates, Inc. in accordance
with rules of the Securities and Exchange Commission, or SEC, and are not intended to represent the fair market value of such reserves.
The present value of future net cash flows
from our proved reserves is not necessarily the same as the current market value of our estimated reserves. We base the estimated
discounted future net cash flows from our proved reserves on prices and costs. However, actual future net cash flows from our oil
and gas properties also will be affected by factors such as:
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assumptions governing future oil and gas prices;
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amount and timing of actual production;
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future operating and development costs;
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actual prices we receive for oil and gas;
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changes in government regulations and taxation; and
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capital costs of drilling new wells
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The timing of both our production and our incurrence of expenses
in connection with the development and production of our properties will affect the timing of actual future net cash flows from
proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted
future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks
associated with our business or the oil and gas industry in general.
The differential between the New York Mercantile Exchange,
or NYMEX, or other benchmark price of oil and gas and the wellhead price we receive could have a material adverse effect on our
results of operations, financial condition and cash flows.
The prices that we receive for our
oil production in Texas, Colorado and Kansas are typically based on a discount to the relevant benchmark prices, such as NYMEX,
that are used for calculating hedge positions. The prices we receive for our natural gas production in Colorado is based upon local
market conditions but generally we receive a discount to Henry Hub. The difference between the benchmark price and the price we
receive is called a differential. We cannot accurately predict oil and gas differentials. In recent years for example, production
increases from competing North American producers, in conjunction with limited refining and pipeline capacity have widened this
differential. Recent economic conditions, including volatility in the price of oil and gas, have resulted in both increases and
decreases in the differential between the benchmark price for oil and gas and the wellhead price we receive. These fluctuations
could have a material adverse effect on our results of operations, financial condition and cash flows by decreasing the proceeds
we receive for our oil and gas production in comparison to what we would receive if not for the differential.
The oil and gas business involves numerous uncertainties
and operating risks that can prevent us from realizing profits and can cause substantial losses.
Our development, exploitation and exploration
activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties.
Moreover, the successful drilling of an oil and gas well does not ensure a profit on investment. A variety of factors, both geological
and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their cost, unsuccessful
wells can hurt our efforts to replace reserves.
The oil and gas business involves a variety
of operating risks, including:
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unexpected operational events and/or conditions;
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reductions in oil and gas prices;
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limitations in the market for oil and gas;
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adverse weather conditions;
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facility or equipment malfunctions;
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oil and gas quality issues;
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pipe, casing, cement or pipeline failures;
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fires, explosions, blowouts, surface cratering, pollution and other
risks or accidents;
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environmental hazards, such as oil spills, pipeline ruptures and discharges
of toxic gases;
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compliance with environmental and other governmental requirements;
and
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uncontrollable flows of oil and gas or well fluids
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If we experience any of these problems,
it could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations.
We could also incur substantial losses as a result of:
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injury or loss of life;
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severe damage to and destruction of property, natural resources and
equipment;
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pollution and other environmental damage;
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clean-up responsibilities;
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regulatory investigation and penalties;
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suspension of our operations; and
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repairs to resume operations
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Because we use third-party drilling contractors
to drill our wells, we may not realize the full benefit of worker compensation laws in dealing with their employees. Our insurance
does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide
enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe
the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally
are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could impact
our operations enough to force us to cease our operations.
Drilling wells is speculative, and any material inaccuracies
in our forecasted drilling costs, estimates or underlying assumptions will materially affect our business.
Developing and exploring for oil and gas
involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs
involved in reaching certain objectives. The budgeted costs of drilling, completing and operating wells are often exceeded and
can increase significantly when drilling costs rise due to a tightening in the supply of various types of oil and gas field equipment
and related services. Drilling may be unsuccessful for many reasons, including geological conditions, weather, cost overruns, equipment
shortages and mechanical difficulties. Moreover, the successful drilling of an oil and gas well does not ensure a profit on investment.
Exploratory wells bear a much greater risk of loss than development wells. A variety of factors, both geological and market-related,
can cause a well to become uneconomical or only marginally economic. Our initial drilling and development sites, and any potential
additional sites that may be developed, require significant additional exploration and development, regulatory approval and commitments
of resources prior to commercial development. If our actual drilling and development costs are significantly more than our estimated
costs, we may not be able to continue our business operations as proposed and would be forced to modify our plan of operation.
Development of our reserves, when established,
may not occur as scheduled and the actual results may not be as anticipated. Drilling activity and lack of access to economically
acceptable capital may result in downward adjustments in reserves or higher than anticipated costs. Our estimates will be based
on various assumptions, including assumptions over which we have control and assumptions required by the SEC relating to oil and
gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. We have control over our
operations that affect, among other things, acquisitions and dispositions of properties, availability of funds, use of applicable
technologies, hydrocarbon recovery efficiency, drainage volume and production decline rates that are part of these estimates and
assumptions and any variance in our operations that affects these items within our control may have a material effect on reserves.
The process of estimating our oil and gas reserves is extremely complex, and requires significant decisions and assumptions
in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Our estimates may not
be reliable enough to allow us to be successful in our intended business operations. Our actual production, revenues, taxes, development
expenditures and operating expenses will likely vary from those anticipated. These variances may be material. In 2015 we had a
carried interest in the drilling of two exploratory wells and we drilled no developmental wells.
Unless we replace our oil and gas reserves, our reserves
and production will decline, which would adversely affect our cash flows and income.
Unless we conduct successful development,
exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those
reserves are produced. Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending
upon reservoir characteristics and other factors. Our future oil and gas production, and, therefore our cash flow and income, are
highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring
additional recoverable reserves. We may be unable to make such acquisitions because we are:
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unable to identify attractive acquisition candidates or negotiate
acceptable purchase contracts with them;
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unable to obtain financing for these acquisitions on economically
acceptable terms; or
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If we are unable to develop, exploit, find
or acquire additional reserves to replace our current and future production, our cash flow and income will decline as production
declines, until our existing properties would be incapable of sustaining commercial production.
In order to exploit successfully our current oil and gas
leases and others that we acquire in the future, we will need to generate significant amounts of capital.
The oil and gas exploration, development
and production business is a capital-intensive undertaking. In order for us to be successful in acquiring, investigating, developing,
and producing oil and gas from our current mineral leases and other leases that we may acquire in the future, we will need to generate
an amount of capital in excess of that generated from our results of operations. In order to generate that additional capital,
we may need to obtain an expanded debt facility and issue additional shares of our equity securities. There can be no assurance
that we will be successful in either obtaining that expanded debt facility or issuing additional shares of our equity securities,
and our inability to generate the needed additional capital may have a material adverse effect on our prospects and financial results
of operations. If we are able to issue additional equity securities in order to generate such additional capital, then those issuances
may occur at prices that represent discounts to our trading price, and will dilute the percentage ownership interest of those persons
holding our shares prior to such issuances. Unless we are able to generate additional enterprise value with the proceeds of the
sale of our equity securities, those issuances may adversely affect the value of our shares that are outstanding prior to those
issuances.
A significant portion of our potential future reserves
and our business plan depend upon secondary recovery techniques to establish production. There are significant risks associated
with such techniques.
We anticipate that a significant portion
of our future reserves and our business plan will be associated with secondary recovery projects that are either in the early stage
of implementation or are scheduled for implementation subject to availability of capital. We anticipate that secondary recovery
will affect our reserves and our business plan, and the exact project initiation dates and, by the very nature of water flood operations,
the exact completion dates of such projects are uncertain. In addition, the reserves and our business plan associated with these
secondary recovery projects, as with any reserves, are estimates only, as the success of any development project, including these
water flood projects, cannot be ascertained in advance. If we are not successful in developing a significant portion of our reserves
associated with secondary recovery methods, then the project may be uneconomic or generate less cash flow and reserves than we
had estimated prior to investing the capital. Risks associated with secondary recovery techniques include, but are not limited
to, the following:
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higher than projected operating costs;
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lower-than-expected production;
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higher costs associated with obtaining capital;
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unusual or unexpected geological formations;
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fluctuations in oil and gas prices;
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shortages of equipment; and
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lack of technical expertise.
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If any of these risks occur, it could adversely
affect our financial condition or results of operations.
Any acquisitions we complete are subject to considerable
risk.
Even when we make acquisitions that we believe
are good for our business, all acquisitions involve potential risks, including, among other things:
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the validity of our assumptions about reserves, future production,
revenues and costs, including synergies;
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an inability to integrate successfully the businesses we acquire;
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a decrease in our liquidity by using our available cash or borrowing
capacity to finance acquisitions;
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a significant increase in our interest expense or financial leverage
if we incur additional debt to finance acquisitions;
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the assumption of unknown liabilities, losses or costs for which we
are not indemnified or for which our indemnity is inadequate;
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the diversion of management’s attention from other business concerns;
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an inability to hire, train or retain qualified personnel to manage
the acquired properties or assets;
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the incurrence of other significant charges, such as impairment of
goodwill or other intangible assets, asset devaluation or restructuring charges;
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unforeseen difficulties encountered in operating in new geographic
or geological areas; and
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customer or key employee losses at the acquired businesses.
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Our decision to acquire a property will depend in part
on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic
and other information, the results of which are often incomplete or inconclusive.
Our reviews of acquired properties can be
inherently incomplete because it is not always feasible to perform an in-depth review of the individual properties involved in
each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor
will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections
may not always be performed on every well, and environmental problems, such as ground water contamination, plugging or orphaned
well liability are not necessarily observable even when an inspection is undertaken.
We must obtain governmental permits and approvals for
drilling operations, which can result in delays in our operations, be a costly and time consuming process, and result in restrictions
on our operations.
Regulatory authorities exercise considerable
discretion in the timing and scope of permit issuances in the regions in which we operate. Compliance with the requirements imposed
by these authorities can be costly and time consuming and may result in delays in the commencement or continuation of our exploration
or production operations and/or fines. Regulatory or legal actions in the future may materially interfere with our operations or
otherwise have a material adverse effect on us. In addition, we are often required to prepare and present to federal, state or
local authorities data pertaining to the effect or impact that a proposed project may have on the environment, threatened and endangered
species, and cultural and archaeological artifacts. Accordingly, the permits we need may not be issued, or if issued, may not be
issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.
Due to our lack of geographic diversification, adverse
developments in our operating areas would materially affect our business.
We currently only lease and operate oil
and gas properties located in Colorado, Nebraska, Kansas and Texas. As a result of this concentration, we may be disproportionately
exposed to the impact of delays or interruptions of production from these properties caused by significant governmental regulation,
transportation capacity constraints, curtailment of production, natural disasters, adverse weather conditions or other events which impact
this area.
We depend on a small number of customers for all, or a
substantial amount of our sales. If these customers reduce the volumes of oil and gas they purchase from us, our revenue and cash
flow will decline to the extent we are not able to find new customers for our production.
In Kansas, we sold oil to three purchasers:
Coffeyville Resources, MV Purchasing and Plains Marketing, LP. There are approximately five potential purchasers of oil in Kansas.
If a key purchaser were to reduce the volume of oil it purchases from us, our revenue and cash available for operations will decline
to the extent we are not able to find new customers to purchase our production at equivalent prices.
We currently sell oil to Sunoco Logistics,
Inc. in Texas. There are numerous purchasers in Texas, but increased production volumes from extensive shale drilling activity
in the area could result in reduced purchases by several of our purchasers.
In Colorado we sold oil to two purchasers:
ARM Energy Management LLC and Plains Marketing, LP. There are a number of potential purchasers of our oil in Colorado but increased
production volumes from the DJ basin could result in reduced purchases by our purchasers. If a key purchaser were to reduce the
volume of oil it purchases from us, our revenue and cash available for operations will decline to the extent we are not able to
find new customers to purchase our production at equivalent prices.
We sell natural gas to United Energy Trading
and Western Operating Company in Colorado. There are other purchasers for our natural gas in Colorado. If a key purchaser were
to reduce the volume of gas it purchases from us, our revenue and cash available for operations will decline to the extent we are
not able to find new customers to purchase our production at equivalent prices.
We are not the operator of some of our properties and
we have limited control over the activities on those properties.
We are not the operator of our Mississippian
Project, and our dependence on the operator of this project limits our ability to influence or control the operation or future
development of this project. Such limitations could materially adversely affect the realization of our targeted returns on capital
related to exploration, drilling or production activities and lead to unexpected future costs.
We may suffer losses or incur liability
for events for which we or the operator of a property have chosen not to obtain insurance.
Our operations are subject to hazards and
risks inherent in producing and transporting oil and gas, such as fires, natural disasters, explosions, pipeline ruptures, spills,
and acts of terrorism, all of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and
other damage to our and others’ properties. As protection against operating hazards, we maintain insurance coverage against some,
but not all, potential losses. In addition, pollution and environmental risks generally are not fully insurable. As a result of
market conditions, existing insurance policies may not be renewed and other desirable insurance may not be available on commercially
reasonable terms, if at all. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material
adverse effect on our business, financial condition and results of operations.
Our hedging activities could result in financial losses
or could reduce our available funds or income and therefore adversely affect our financial position.
To achieve more predictable cash flow
and to reduce our exposure to adverse fluctuations in the prices of oil and gas, we have entered into derivative contracts
through December 31, 2016 for approximately 84,000 barrels of crude oil. The settlement of and the mark to market of
these contracts could result in both realized and unrealized hedging losses. For the year ended December 31, 2015, we
incurred net realized and unrealized gains of approximately $2,500,000. The extent of our commodity price exposure is related
largely to the effectiveness and scope of our derivative activities. For example, the derivative instruments we may utilize
may be based on posted market prices, which may differ significantly from the actual crude oil prices we realize in our
operations.
Our actual future production may be significantly
higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher
than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal
amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative
transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in
a substantial diminution of our liquidity. As a result of these factors, our derivative activities may not be as effective as
we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our
cash flows. In addition, while we believe our existing derivative activities are with creditworthy counterparties, deterioration
in the credit markets may cause a counterparty not to perform its obligation under the applicable derivative instrument or impact
their willingness to enter into future transactions with us. If that occurred, then any hedging arrangement with such counterparty
would not provide any effective hedge against changes in market conditions.
Our business depends in part on processing facilities
owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and
gas production and could harm our business.
The marketability of our oil and gas production
will depend in part on the availability, proximity and capacity of pipelines and oil and gas processing facilities. The amount
of oil and gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions
due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on such systems.
The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we will
be provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment
in pipeline capacity or the capacity of processing facilities could significantly reduce our ability to market our oil and gas
production and could materially harm our business.
Cost and availability of drilling rigs, equipment, supplies,
personnel and other services could adversely affect our ability to execute on a timely basis our development, exploitation and
exploration plans.
Shortages or an increase in cost of drilling
rigs, equipment, supplies or personnel could delay or interrupt our operations, which could impact our financial condition and
results of operations. Drilling activity in the geographic areas in which we conduct drilling activities may increase, which would
lead to increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services
and products of other vendors to the industry. Increased drilling activity in these areas may also decrease the availability of
rigs. We do not have any contracts for drilling rigs and drilling rigs may not be readily available when we need them. Drilling
and other costs may increase further and necessary equipment and services may not be available to us at economical prices.
Our exposure to possible leasehold defects and potential
title failure could materially adversely impact our ability to conduct drilling operations.
We obtain the right and access to properties
for drilling by obtaining oil and gas leases either directly from the hydrocarbon owner, or through a third party that owns the
lease. The leases may be taken or assigned to us without title insurance. There is a risk of title failure with respect to such
leases, and such title failures could materially adversely impact our business by causing us to be unable to access properties
to conduct drilling operations.
Our reserves are subject to the risk of depletion because
many of our leases are in mature fields that have produced large quantities of oil and gas to date.
A significant portion of our operations
are located in or near established fields in Colorado, Nebraska, Kansas and Texas. As a result, many of our leases are in, or directly
offset, areas that have produced large quantities of oil and gas to date. As such, our reserves may be negatively impacted
by offsetting wells or previously drilled wells, which could significantly harm our business.
Our lease ownership may be diluted
due to financing strategies we may employ in the future.
To accelerate our development efforts we
may take on working interest partners who will contribute to the costs of drilling and completion operations and then share in
any cash flow derived from production. In addition, we may in the future, due to a lack of capital or other strategic reasons,
establish joint venture partnerships or farm out all or part of our development efforts. These economic strategies may have a dilutive
effect on our lease ownership and could significantly reduce our operating revenues.
We may face lease expirations on leases that are not currently
held-by-production.
We have numerous leases that are not currently
held-by-production, some of which have near term lease expirations and are likely to expire. Although we believe that we can maintain
our most desirable leases by conducting drilling operations or by negotiating lease extensions, we can make no guarantee that we
can maintain these leases.
We are subject to complex laws and regulations, including
environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.
Development, production and sale of oil
and gas in the United States are subject to extensive laws and regulations, including environmental laws and regulations. We may
be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation
include, but are not limited to:
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location and density of wells;
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the handling of drilling fluids and obtaining discharge permits for
drilling operations;
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accounting for and payment of royalties on production from state,
federal and Indian lands;
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bonds for ownership, development and production of oil and gas properties;
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transportation of oil and gas by pipelines;
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operation of wells and reports concerning operations; and
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Under these laws and regulations, we could
be liable for personal injuries, property damage, oil and gas spills, discharge of hazardous materials, remediation and clean-up
costs and other environmental damages. Failure to comply with these laws and regulations also may result in the suspension or termination
of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change
in ways that substantially increase our costs. Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory
changes could materially adversely affect our financial condition and results of operations enough to possibly force us to cease
our business operations.
Our operations may expose us to significant costs and
liabilities with respect to environmental, operational safety and other matters.
We may incur significant costs and liabilities
as a result of environmental and safety requirements applicable to our oil and gas production activities. We may also be exposed
to the risk of costs associated with Kansas Corporation Commission, the Texas Railroad Commission and the State of Colorado Oil
and Gas Conservation Commission requirements to plug orphaned and abandoned wells on our oil and gas leases from wells previously
drilled by third parties. In addition, we may indemnify sellers or lessors of oil and gas properties for environmental liabilities
they or their predecessors may have created. These costs and liabilities could arise under a wide range of federal, state and local
environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly
strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal
penalties, imposition of cleanup and site restoration costs, liens and to a lesser extent, issuance of injunctions to limit or
cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of our
operations.
Strict, joint and several liability may
be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences
of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations
or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If
we are not able to recover the resulting costs through insurance or increased revenues, our ability to operate effectively could
be adversely affected.
We operate in a highly competitive environment and our
competitors may have greater resources than do we.
The oil and gas industry is intensely competitive
and we compete with other companies, many of which are larger and have greater financial, technological, human and other resources.
Many of these companies not only explore for and produce crude oil and gas but also carry on refining operations and market petroleum
and other products on a regional, national or worldwide basis. Such companies may be able to pay more for productive oil and gas
properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than
our financial or human resources permit. In addition, such companies may have a greater ability to continue exploration activities
during periods of low oil and gas market prices. Our ability to acquire additional properties and to discover reserves in the future
will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive
environment. If we are unable to compete, our operating results and financial position may be adversely affected.
Risks Associated with our Stock
We have ceased
paying dividends on our Series A preferred stock, causing the trading price of the preferred stock to dramatically decline
On November 4, 2015, we announced that we
would not be declaring the monthly dividend for the month of November 2015 on our 10.00% Series A Cumulative Redeemable Perpetual
Preferred Stock in order to preserve our cash resources. We have not declared the monthly dividend since, and do not expect to
do so in the near future. The failure to declare and pay monthly dividends on our preferred stock caused its trading price to decline
substantially.
We do not expect to pay dividends
to holders of our common stock because of the terms of our debt facility, and our need to reinvest cash flow from operations in
our business.
It is unlikely that we will pay any dividends
to the holders of our common stock in the foreseeable future. The terms of our debt facility require that the lender approve any
such distributions, and the lender is unlikely to provide that consent so long as we have significant unpaid indebtedness outstanding.
Ownership of our common stock is highly concentrated,
and such concentration may prevent other stockholders from influencing significant corporate decisions and may result in conflicts
of interest that could cause our stock price to decline.
Our directors, officers and principal stockholders
(stockholders owning 10% or more of our common stock) and their affiliates beneficially owned approximately 4,367,140 shares or
54.1% of the outstanding shares of common stock, stock options, and derivatives that could have been converted to common stock
at December 31, 2015, and 54.2% of the outstanding shares of common stock, options and derivatives that could have been converted
to common stock as of the filing of this Annual Report on Form 10-K. Such stockholders will have significant influence over the
outcome of all matters submitted to our stockholders for approval, including the election of directors and other corporate actions.
Two of our Directors, Ryan A. Lowe and Lance
W. Helfert, serve on the investment committee of West Coast Asset Management, Inc. West Coast Asset Management is the managing
member of West Coast Opportunity Fund, LLC, a private investment vehicle formed for the purpose of investing in a wide variety
of securities and financial instruments. West Coast Asset Management’s principals also manage Montecito Venture Partners, LLC.
West Coast Opportunity Fund was dissolved in 2015 and EnerJex common and preferred shares were distributed to the owners of West
Coast Opportunity Fund, LLC. Montecito Venture Partners, LLC beneficially owned 7% of our common stock and .7% of our Series A
preferred stock at December 31, 2015. Currently they own 7% of our common stock and .7% of our Series A preferred stock.
In addition, we engage from time to time
in transactions with certain of these significant stockholders.
As stated above, Montecito Venture Partners
affiliates of our directors Mr. Lowe and Mr. Helfert, beneficially own, as of December 31, 2015, 7% of our common stock and .7%
of our Series A preferred stock. The interests of Montecito Venture Partners, and their affiliates, may differ from those of our
other stockholders. Montecito Venture Partners, and their affiliates are in the business of making investments in companies
and maximizing the return on those investments. They currently have, and may from time to time in the future acquire, interests
in businesses that directly or indirectly compete with certain aspects of our business or our suppliers’ or customers’ businesses.
Montecito Venture Partners was a party to
an irrevocable voting and proxy agreement, by which Montecito Venture Partners granted to West Coast Asset Management, Inc. a proxy to
vote Montecito Venture Partners shares with regard to the election of our board of directors. On March 23, 2015, the irrevocable
voting and proxy agreement was terminated pursuant to written agreement.
We have derivative securities currently outstanding and
we may issue derivative securities in the future. Exercise of the derivatives will cause dilution to existing and new stockholders.
The exercise of our outstanding options
and warrants, will cause additional shares of common stock to be issued, resulting in dilution to our existing and future common
stockholders
We have the ability to issue additional shares of our
common stock and preferred stock without asking for stockholder approval, which could cause your investment to be diluted.
Our amended and restated articles of incorporation
authorize the board of directors to issue up to 250,000,000 shares of common stock and 25,000,000 shares of preferred stock.
The power of the board of directors to issue shares of common stock, preferred stock or warrants or options to purchase shares
of common stock or preferred stock is generally not subject to shareholder approval. Accordingly, any additional issuance
of our common stock, or preferred stock that may be convertible into common stock, or debt instruments that may be convertible
into common or preferred stock, may have the effect of diluting one’s investment.
Although our common stock and Series A preferred stock
are traded on the NYSE MKT, daily trading volumes are small making it difficult for investors to sell their shares.
Our common stock and our Series A preferred
stock trade on the NYSE MKT under the symbol “ENRJ,” and “ENRJ.P,” respectively but trading volume has been
minimal. Therefore, the market for our common stock is limited. The trading price of our stock could be subject to wide fluctuations.
Investors may not be able to purchase additional shares or sell their shares within the time frame or at a price they desire.
The price of our common stock and
Series A preferred stock may be volatile and you may not be able to resell your shares at a favorable price.
Regardless of whether an active trading
market for our stock develops, the market price of our stock may be volatile and you may not be able to resell your shares at or
above the price you paid for such shares. Many factors beyond our control, including but not limited to the following factors could
affect our stock price:
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our operating and financial performance and prospects;
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quarterly variations in the rate of growth of our financial indicators,
such as net income or loss per share, net income or loss and revenues;
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changes in revenue or earnings estimates or publication of research
reports by analysts about us or the exploration and production industry;
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potentially limited liquidity;
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actual or anticipated variations in our reserve estimates and quarterly
operating results;
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changes in oil and gas prices;
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sales of our common stock by significant stockholders and future issuances
of our common stock;
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increases in our cost of capital;
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changes in applicable laws or regulations, court rulings and enforcement
and legal actions;
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commencement of or involvement in litigation;
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changes in market valuations of similar companies;
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additions or departures of key management personnel;
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general market conditions, including fluctuations in and the occurrence
of events or trends affecting the price of oil and gas; and
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domestic and international economic, legal and regulatory factors
unrelated to our performance.
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Our amended and restated articles of incorporation, restated
bylaws and Nevada Law contain provisions that could discourage an acquisition or change of control of us.
Our amended and restated articles of incorporation
authorize our board of directors to issue preferred stock and common stock without stockholder approval. The election by our board
of directors to issue Series A preferred stock, and any future election to issue more preferred stock, could make it more difficult
for a third party to acquire control of us. In addition, provisions of the articles of incorporation and bylaws could also make
it more difficult for a third party to acquire control of us. In addition, Nevada’s “Combination with Interested Stockholders’
Statute” and its “Control Share Acquisition Statute” may have the effect in the future of delaying or making it
more difficult to effect a change in control of us.
These statutory anti-takeover measures may
have certain negative consequences, including an effect on the ability of our stockholders or other individuals to (i) change the
composition of the incumbent board of directors; (ii) benefit from certain transactions which are opposed by the incumbent board
of directors; and (iii) make a tender offer or attempt to gain control of us, even if such attempt were beneficial to us and our
stockholders. Since such measures may also discourage the accumulations of large blocks of our common stock by purchasers whose
objective is to seek control of us or have such common stock repurchased by us or other persons at a premium, these measures could
also depress the market price of our common stock. Accordingly, our stockholders may be deprived of certain opportunities to realize
the “control premium” associated with take-over attempts.
We have no plans to pay dividends on our common stock.
You may not receive funds without selling your stock.
We do not anticipate paying any cash dividends
on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion
of our business. Our future dividend policy with regard to our common stock is within the discretion of our board of directors
and will depend upon various factors, including our business, financial condition, results of operations, capital requirements,
investment opportunities and restrictions contained in current or future financing instruments, including the consent of debt
holders and holders of Series A Shares, if applicable at such time, and other factors our Board of Directors deems relevant.
Additional Risks and Uncertainties
We are an oil and gas acquisition, exploration
and development company. If any of the risks that we face actually occur, irrespective of whether those risks are described in
this section or elsewhere in this report, our business, financial condition and operating results could be materially adversely
affected.