UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K/A
[X]
Annual Report Pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934
For
the Fiscal Year Ended December 31, 2013
[ ]
Transition Report Pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934
Commission
File Number: 0-52718
OSAGE
EXPLORATION AND DEVELOPMENT, INC.
(Exact
name of registrant as specified in its charter)
| Delaware |
|
26-0421736 |
(State
of other jurisdiction of
incorporation or organization) |
|
(I.R.S.
Employer
Identification No.) |
2445
Fifth Avenue, Suite 310, San Diego, California 92101
(Address
of principal executive offices) (Zip Code)
Registrant’s
telephone no.: (619) 677-3956
Securities
registered pursuant to Section 12(b) of the Exchange Act: None
Securities
registered pursuant to Section 12(g) of the Exchange Act: Common stock, par value $0.0001
Indicate
by check mark is the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [ ]
No [X]
Indicate
by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ]
No [X]
Indicate
by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Security Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports),
and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not
be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K of any amendment to this Form 10-K. [X]
Indicate
by check mark whether registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting
company. See the definitions of “accelerated filer,” “large accelerated filer,” and “smaller reporting
company” in Rule 12b-2 of the Exchange Act. (Check one):
Large
Accelerated Filer [ ] Accelerated filer [ ] Non-accelerated filer [ ]
Smaller reporting company [X]
Indicate
by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes [ ] No [X]
The
aggregate market value of the issuer’s Common stock held by non-affiliates of the registrant on June 30, 2013 was approximately
$32,413,158 based on the closing price of $1.05 as reported on the NASD’s OTC Electronic Bulletin Board system.
As
of March 27, 2014, there were 57,591,342 shares of Osage Exploration and Development, Inc., Common stock, par value $0.0001, outstanding.
TABLE
OF CONTENTS
OSAGE EXPLORATION
AND DEVELOPMENT, INC.
EXPLANATORY NOTE
This Annual Report on Form 10-K/A (“Form
10-K/A”) is being filed as Amendment No. 1 (the “Amendment”) to our Annual Report on Form 10-K for the year
ended December 31, 2013, which was filed with the Securities and Exchange Commission (the “SEC”) on March 31, 2014
(the “Original Annual Report”). The purpose of the Amendment is expand certain disclosures with respect to properties
and estimated proved developed and undeveloped reserves pursuant to SEC staff comments.
This Form 10-K/A also includes as exhibits
certifications from our Chief Executive Officer and Chief Financial Officer dated as of the date of this filing.
This Amendment does not change our previously
reported financial statements or the other financial disclosures contained in the Original Annual Report. This Amendment does
not reflect events occurring after the filing of the Original Annual Report and no attempt has been made in this Amendment to
modify or update other disclosures as presented in the Original Annual Report.
Cautionary
Statement
IN
ADDITION TO HISTORICAL INFORMATION, THIS ANNUAL REPORT CONTAINS FORWARD-LOOKING STATEMENTS WITHIN THE MEANING OF THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995 AND THE COMPANY DESIRES TO TAKE ADVANTAGE OF THE “SAFE HARBOR” PROVISIONS THEREOF. THEREFORE,
THE COMPANY IS INCLUDING THIS STATEMENT FOR THE EXPRESS PURPOSE OF AVAILING ITSELF OF THE PROTECTIONS OF SUCH SAFE HARBOR WITH
RESPECT TO ALL OF SUCH FORWARD-LOOKING STATEMENTS. THE FORWARD-LOOKING STATEMENTS IN THIS REPORT REFLECT THE COMPANY’S CURRENT
VIEWS WITH RESPECT TO FUTURE EVENTS AND FINANCIAL PERFORMANCE. THESE FORWARD-LOOKING STATEMENTS ARE SUBJECT TO CERTAIN RISKS AND
UNCERTAINTIES, INCLUDING THOSE DISCUSSED HEREIN, THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM HISTORICAL RESULTS
OR THOSE ANTICIPATED. IN THIS REPORT, THE WORDS “ANTICIPATES,” “BELIEVES,” “EXPECTS,” “INTENDS,”
“FUTURE” AND SIMILAR EXPRESSIONS IDENTIFY FORWARD-LOOKING STATEMENTS. READERS ARE CAUTIONED TO CONSIDER THE SPECIFIC
RISK FACTORS DESCRIBED BELOW AND NOT TO PLACE UNDUE RELIANCE ON THE FORWARD-LOOKING STATEMENTS CONTAINED HEREIN, WHICH SPEAK ONLY
AS OF THE DATE HEREOF. THE COMPANY UNDERTAKES NO OBLIGATION TO PUBLICLY REVISE THESE FORWARD-LOOKING STATEMENTS TO REFLECT EVENTS
OR CIRCUMSTANCES THAT MAY ARISE AFTER THE DATE HEREOF.
PART
I
Item
1. Business
Overview
Osage
Exploration and Development, Inc., (“Osage” or the “Company”) is an oil and natural gas exploration and
production company with proved reserves and existing production in the state of Oklahoma. We are headquartered in San Diego, California
with operations offices in Oklahoma City, Oklahoma.
Mississippian
In
2010, we began to acquire oil and gas leases in Logan County, Oklahoma targeting the Mississippian formation. The Mississippian
formation is located on the Anadarko Shelf in northern Oklahoma and south-central Kansas. The top of this expansive carbonate
hydrocarbon system is encountered between 4,000 and 6,000 feet and lies stratigraphically between the Pennsylvanian-aged Morrow
Sand and the Devonian-aged Oily Woodford Shale formations. The Mississippian formation may reach 600 feet in gross thickness and
the targeted porosity zone is between 50 and 300 feet in thickness. The formation’s geology is well understood as a result
of the thousands of vertical wells drilled and produced there since the 1940s. Beginning in 2007, the application of horizontal
cased-hole drilling and multi-stage hydraulic fracturing treatments have demonstrated the potential for extracting significant
additional quantities of oil and natural gas from the formation.
Woodford Shale
The
Woodford Shale is a major energy resource with the potential for significant unconventional oil and gas production. The Woodford
is a Devonian aged, highly carboniferous black shale that has sourced the vast majority of migratable hydrocarbons in Oklahoma
and Kansas. The known inefficacies of hydrocarbon expulsion is the primary reason why source rocks like the Woodford retain large
volumes of oil and gas. Currently, there are more than 1,500 producing horizontal Woodford wells in Oklahoma. This world class
source rock underlies all of our Mississippian acreage.
Cimarrona
On
April 8, 2008, we entered into a membership interest purchase agreement (the “Purchase Agreement”) with Sunstone Corporation
pursuant to which we acquired from them 100% of the membership interests in Cimarrona Limited Liability Company (“Cimarrona
LLC”), an Oklahoma limited liability company. Cimarrona LLC owns a 9.4% interest in certain oil and gas assets in the Guaduas
field, located in the Dindal and Rio Seco Blocks that consist of twenty-one wells, of which seven are currently producing, that
covers 30,665 acres in the Middle Magdalena Valley in Colombia, as well as a pipeline with a current capacity of approximately
40,000 barrels of oil per day.
On
October 7, 2013, the Company completed the sale of 100% of the membership interests in Cimarrona LLC to Raven Pipeline Company,
LLC (“Raven”), pursuant to a Membership Interest Purchase Agreement dated September 30, 2013 (the “Agreement”)
by and between the Company and Raven. We had classified Cimarrona as discontinued operations from August 1, 2013, as it had received
an expression of interest and had concluded that a sale of its membership interests was in the best interest of stockholders.
The
sales price consisted of cash of $6,800,000, less settlement of debt of Cimarrona LLC of approximately $250,000. Of the net sales
price, $250,000 is being held in escrow for 12 months to secure any post-Closing purchase price adjustments and any indemnity
obligations of the Company pursuant to the Agreement. In addition, as long as the per barrel transportation rate charged with
respect to the pipeline is not adjusted prior to March 31, 2014, then Raven will pay the Company an additional $1,000,000 in cash.
Pursuant to the Agreement, the Company also recognized a receivable for a working capital adjustment of $422,955 in other current
assets as of December 31, 2013 and recognized a gain on disposal of discontinued operations of $4,873,660 in the year ended December
31, 2013.
The
Cimarrona property is subject to an Ecopetrol Association Contract (the “Association Contract”) whereby Ecopetrol
S.A. (“Ecopetrol”) receives royalties of 20% of the oil produced. The pipeline is not subject to the Association Contract.
In addition to the royalty, according to the Association Contract, Ecopetrol may, for no consideration, become a 50% partner,
once an audit of revenues and expenses indicate that the partners in the Association Contract have received a 200% reimbursement
of all historical costs to develop and operate the Guaduas field. If such an audit determines that the specified reimbursement
of historical costs occurred prior to September 30, 2013, the Company is required to reimburse Raven for any amounts due to Ecopetrol
from Cimarrona LLC which relate to the period prior to that date. The
Company believes its maximum exposure is 50% of Cimarrona LLC’s oil revenues for the nine months ended September 30, 2013,
or $729,308. The Company has not recorded any provision for this matter, as it is not possible to estimate the potential liability,
if any.
Background
We
were organized September 9, 2004 as Osage Energy Company, LLC, an Oklahoma limited liability company. On April 24, 2006, we merged
with a non-reporting Nevada corporation trading on the Pink Sheets, Kachina Gold Corporation, which was the entity that survived
the merger. The merger was consummated through the issuance of 10,000,000 shares of our common stock. The financial records of
the Company prior to merger are those of Osage Energy Company, LLC.
The
Nevada corporation was incorporated under the laws of Canada, on February 24, 2003, as First Mediterranean Gold Resources, Inc.
The domicile of the Company was changed to the State of Nevada, on May 11, 2004. On May 24, 2004, the name of the Company was
changed to Advantage Opportunity Corp.
On
March 4, 2005, the Company changed its name to Kachina Gold Corporation. On April 24, 2006, Kachina Gold Corporation merged with
Osage Energy Company, LLC. and on May 15, 2006 changed its name to Osage Energy Corporation. On July 2, 2007, the domicile of
the Company was changed to Delaware and in connection therewith, the name of the Company was changed to Osage Exploration and
Development, Inc. On February 27, 2008, our stock began trading on the NASDAQ OTC Bulletin Board market under the ticker “OEDV”.
Our
principal office is located at 2445 Fifth Avenue, Suite 310, San Diego, California 92101. Our phone number is (619) 677-3956.
Distribution
Methods
We
currently generate oil, natural gas and natural gas liquid sales from our production operations in the state of Oklahoma. Slawson
Exploration Company (“Slawson”) is the operator of the majority of our Logan County, Oklahoma, oil and gas properties
and the remainder are operated by three other operators, Stephens Production Company (“Stephens”), Devon Energy Production
Co. LLC (“Devon”), and Sundance Energy Co. All of the oil, natural gas and natural gas liquids produced at these properties
is sold by the operators on our behalf at market prices at the time of sale. Each operator is responsible for remitting our share
of the oil and gas revenues to us. There is significant demand for oil and gas and there are several companies in our area that
purchase oil from small oil producers.
In
2013, Slawson, Stephens and Devon accounted for 80.0%, 10.6% and 9.2% of our revenues from continuing operations, respectively.
In 2012, Slawson and Devon accounted for 97.4% and 0.7% of revenues from continuing operations, respectively.
Research
and Development
We
have not allocated funds to conducting research and development activities, nor do we anticipate allocating funds to research
and development in the future.
Patents,
Trademarks, Royalties, Etc.
We
have no patents, trademarks, licenses, concessions, or labor contracts.
Royalty
rates range from 12.5% to 25.0% on our leases in Logan, Coal and Pawnee counties in Oklahoma. Most of our leases require us to
drill a well on the lease within three years of entering into a lease. If we do not drill during that time and do not have an
option to extend the lease, we will lose that lease.
Government
Approvals
We
are required to get approval from the Oklahoma Corporation Commission before any work can begin on any well in Oklahoma and before
production can be sold. We have all of the required permits on the properties currently in operation.
Existing
or Probable Governmental Regulations
We,
currently, are active in the state of Oklahoma. The development and operation of oil and gas properties is highly regulated by
states and/or foreign governments. In some areas of exploration and production, the United States government or a foreign governmental
agency regulates the industry.
Regulations,
whether state or federal or international, control numerous aspects of drilling and operating oil and gas wells, including the
care of the environment, the safety of the workers and the public, and the relations with the owners and occupiers of the surface
lands within or near the leasehold acreage. The effect of these regulations, whether state or federal or international, is invariably
to increase the cost of operations.
The
costs of complying with state regulations include a permit for drilling a well before beginning a project. Other compliance matters
have to do with keeping the property free of oil spills and the plugging of wells when they no longer produce. If oil spills are
not cleaned up on a timely basis fines can be significant. We utilize consultants and independent contractors to visit and monitor
our properties in Oklahoma on a regular basis to prevent mishaps and ensure prompt attention and, if necessary, appropriate correction
and remedial activity. The other significant cost of compliance with state regulations is the plugging of wells after their useful
life. In most instances, there is pumping equipment and pipe which can be salvaged to offset some if not all of that cost. Plugging
a well consists of pumping cement into the well bore sufficient to prevent any oil and gas zone from ever leaking and contaminating
the fresh water supply.
Costs
and Effects of Compliance with Environmental Laws
There
is a cost in complying with environmental laws that is associated with each well that is drilled or operated, which cost is added
to the cost of the operation. Each well will have an additional cost associated with plugging and abandoning the well when it
is no longer commercially viable. As of December 31, 2013 we have not incurred any dismantlement and abandonment costs.
Employees
We
currently have six full-time employees, including two full-time executive employees: Kim Bradford, President, Chief Executive
Officer and Greg Franklin, Chief Geologist. We utilize third parties to provide certain operational, technical, accounting, finance
and administrative services. As production levels increase, we may need to hire additional personnel or expand the use of third
parties.
Facilities
We
lease 1,386 square feet of modern office space in San Diego, California as our corporate headquarters pursuant to a 36 month lease
from February 2011, which was renewed for an additional 36 month period through February 2017. Monthly rent is $2,980, $3,084
and $3,192 for the first, second and third years, respectively, of the renewal period.
In
December 2013, we entered into a 36 month lease commencing in March 2014 for 6,368 feet of executive office space for our production
offices in Oklahoma City, Oklahoma. Monthly rent for this space is $11,114 for the entire duration of the lease.
In
the case of both of these leases we are also responsible for our proportionate share of common area expenses.
Available
Information
Our
Internet website address is www.osageexploration.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to section 13(a) or 15(d) of the Securities
Exchange Act of 1934, as amended (the “Exchange Act”) are available free of charge through our Company’s website
as soon as reasonably practicable after those reports are electronically filed with, or furnished to, the Securities and Exchange
Commission (the “SEC”).
Item
1A. Risk Factors
Cautionary
Note on Forward Looking Statements
In
addition to the other information in this annual report the factors listed below should be considered in evaluating our business
and prospects. This annual report contains a number of forward-looking statements that reflect our current views with respect
to future events and financial performance. These forward-looking statements are subject to certain risks and uncertainties, including
those discussed below and elsewhere herein, that could cause actual results to differ materially from historical results or those
anticipated. In this report, the words “anticipates,” “believes,” “expects,” “intends,”
“future” and similar expressions identify forward-looking statements. Readers are cautioned to consider the specific
factors described below and not to place undue reliance on the forward-looking statements contained herein, which speak only as
of the date hereof. We undertake no obligation to publicly revise these forward-looking statements, to reflect events or circumstances
that may arise after the date hereof.
Risks
Relating to Our Business
We
have a history of losses and may incur future losses.
We
have incurred significant operating losses in prior years and at December 31, 2013 had an accumulated deficit of $4,219,480. In
2013, we recognized a one-time gain of $4,873,660 on the sale of 100% of our membership interests in Cimarrona, LLC. Given the
level of operating expenditures and the uncertainty of revenues and margins, we may continue to incur losses and negative cash
flows in future periods. The failure to obtain sufficient revenues and margins to support operating expenses could harm our business.
The audit opinion in the accompanying consolidated financial statements has a paragraph expressing substantial doubt about the
Company’s ability to continue as a going concern.
We
have limited operating capital.
To
continue growth and to fund our expansion plans, we will require additional financing. The amount of capital available to us is
limited, and may not be sufficient to enable us to fully execute our growth plans without additional fund raising. Additional
financing may be required to meet our objectives and provide more working capital for expanding our development and marketing
capabilities and to achieve our ultimate plan of expansion and full scale of operations. There is no assurance we will be able
to obtain such financing on attractive terms, if at all.
We
do not intend to pay dividends to our stockholders.
We
do not currently intend to pay cash dividends on our common stock and do not anticipate paying any dividends at any time in the
foreseeable future. At present, we will follow a policy of retaining all of our earnings, if any, to finance development and expansion
of our business.
Our
officers and directors have limited liability, and we are required in certain instances to indemnify our officers and directors
for breaches of their fiduciary duties.
We
have adopted provisions in our Certificate of Incorporation and Bylaws which limit the liability of our officers and directors
and provide for indemnification by us of our officers and directors to the full extent permitted by Delaware corporate law. Our
Certificate of Incorporation generally provides that our officers and directors shall have no personal liability to us or our
stockholders for monetary damages for breaches of their fiduciary duties as directors, except for breaches of their duties of
loyalty, acts or omissions not in good faith or which involve intentional misconduct or knowing violation of law, acts involving
unlawful payment of dividends or unlawful stock purchases or redemptions, or any transaction from which a director derives an
improper personal benefit. Such provisions substantially limit our stockholders’ ability to hold officers and directors
liable for breaches of fiduciary duty, and may require us to indemnify our officers and directors.
We
face great competition.
We
compete against many other energy companies, some of which have considerably greater resources and abilities. These competitors
may have greater marketing and sales capacity, established distribution networks, significant goodwill and global name recognition.
Our
success depends to a significant degree upon the involvement of our management, who are in charge of our strategic planning and
operations. We may need to attract and retain additional talented individuals in order to carry out our business objectives. The
competition for such persons could be intense and there are no assurances that these individuals will be available to us.
Our
business is subject to extensive regulation.
Many
of our activities are subject to federal, state and/or local regulation, and as these rules are subject to constant change or
amendment, there can be no assurance that our operations will not be adversely affected by new or different government regulations,
laws or court decisions applicable to our operations.
Government
regulation and liability for environmental matters may adversely affect our business and results of operations.
Crude
oil and natural gas operations are subject to extensive international, federal, state and local government regulations, which
may be changed from time to time. Matters subject to regulation include discharge permits for drilling operations, drilling bonds,
reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory
agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil and natural gas
wells below actual production capacity in order to conserve supplies of crude oil and natural gas. There are international, federal,
state and local laws and regulations primarily relating to protection of human health and the environment applicable to the development,
production, handling, storage, transportation and disposal of crude oil and natural gas, by products thereof and other substances
and materials produced or used in connection with crude oil and natural gas operations. In addition, we may inherit liability
for environmental damages caused by previous owners of property we purchase or lease. As a result, we may incur substantial liabilities
to third parties or governmental entities. We are also subject to changing and extensive tax laws, the effects of which cannot
be predicted. The implementation of new, or the modification of existing, laws or regulations could have a material adverse effect
on us.
The
reserves we report in our SEC filings are estimates and may prove to be inaccurate.
There
are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their estimated values. The reserves
we report in our filings with the SEC are only estimates and may prove to be inaccurate because of these uncertainties. Reservoir
engineering is a subjective and inexact process of estimating underground accumulations of crude oil, natural gas and natural
gas liquids that cannot be measured in an exact manner. Estimates of economically recoverable crude oil and natural gas reserves
depend upon a number of variable factors, such as historical production from the area compared with production from other producing
areas and assumptions concerning effects of regulations by governmental agencies, future crude oil and natural gas prices, future
operating costs, severance and excise taxes, development costs and work-over and remedial costs. Some or all of these assumptions
may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of
crude oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of
recovery, and estimates of the future net cash flows expected there from prepared by different engineers or by the same engineers
but at different times may vary substantially. Accordingly, reserve estimates may be subject to downward or upward adjustment.
Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may
be material.
Crude
oil prices are highly volatile in general and low prices will negatively affect our financial results.
Our
revenues, operating results, profitability, cash flow, future rate of growth and ability to borrow funds or obtain additional
capital are substantially dependent upon prevailing prices of crude oil. Lower crude oil and natural gas prices also may reduce
the amount of crude oil and natural gas that we can produce economically. Historically, the markets for crude oil and natural
gas have been very volatile, and such markets are likely to continue to be volatile in the future. Prices for crude oil and natural
gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for crude oil and natural
gas, market uncertainty and a variety of additional factors that are beyond our control, including: worldwide and domestic supplies
of crude oil and natural gas; the level of consumer product demand; weather conditions; domestic and foreign governmental regulations;
the price and availability of alternative fuels; political instability or armed conflict in oil producing regions; the price and
level of foreign imports; and overall domestic and global economic conditions.
At
our Oklahoma properties, we sold oil at $88.90 to $106.32 per barrel in 2013 compared to $79.79 to $106.49 per barrel in 2012.
We have entered into certain derivative financial instruments to partially mitigate the risk of lower oil and gas prices.
Risks
Relating to Trading in Our Common stock
The
market price for our common stock may be volatile, and you may not be able to sell our stock at a favorable price or at all.
Many
factors could cause the market price of our common stock to rise and fall, including: actual or anticipated variations in our
quarterly results of operations; changes in market valuations of companies in our industry; changes in expectations of future
financial performance; fluctuations in stock market prices and volumes; issuances of dilutive common stock or other securities
in the future; the addition or departure of key personnel; and the increase or decline in the price of oil and natural gas. It
is possible that the proceeds from sales of our common stock may not equal or exceed the prices you paid for it plus the costs
and fees of making the sales.
Substantial
sales of our common stock, or the perception that such sales might occur, could depress the market price of our common stock.
We
cannot predict whether future issuances of our common stock or resales in the open market by current stockholders will decrease
the market price of our common stock. The impact of any such issuances or resales of our common stock on our market price may
be increased as a result of the fact that our common stock is thinly, or infrequently, traded. The exercise of any options, warrants
or the vesting of any restricted stock that we may grant to directors, officers, employees and consultants in the future, the
issuance of common stock in connection with acquisitions and other issuances of our common stock could have an adverse effect
on the market price of our common stock. In addition, future issuances of our common stock may be dilutive to existing stockholders.
Any sales of substantial amounts of our common stock in the public market, or the perception that such sales might occur, could
lower the market price of our common stock.
Our
common stock is considered to be a “penny stock” security under the Exchange Act rules, which may limit the marketability
of our securities.
Our
securities are considered low-priced or “designated” securities under rules promulgated under the Exchange Act. Under
these rules, broker/dealers participating in transactions in low-priced securities must first deliver a risk disclosure document
which describes the risks associated with such stocks, the broker/dealers’ duties, the customer’s rights and remedies,
certain market and other information, and make a suitability determination approving the customer for low-priced stock transactions
based on the customer’s financial situation, investment experience and objectives. Broker/dealers must also disclose these
restrictions in writing to the customer and obtain specific written consent of the customer, and provide monthly account statements
to the customer. The likely effect of these restrictions is a decrease in the willingness of broker/dealers to make a market in
the stock, decreased liquidity of the stock and increased transaction costs for sales and purchases of the stock as compared to
other securities.
Item
1B. Unresolved Staff Comments
None
Item
2. Properties
The
principal assets of the Company consist of proved and unproved oil and gas properties and oil and gas production related equipment.
Our oil and gas properties are located in the state of Oklahoma.
Developed
oil and gas properties are those on which sufficient wells have been drilled to economically recover the estimated reserves calculated
for the property. Undeveloped properties do not presently have sufficient wells to recover the estimated reserves.
There
are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and
timing of development expenditures, including many factors beyond the control of the Company and the operators. The reserve data
set forth in Supplemental Information to Consolidated Financial Statements represent only estimates. Reserve engineering is a
subjective process of estimating underground accumulations of crude oil and condensate, natural gas liquids and natural gas that
cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available
data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary.
In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate
upward or downward. Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness
of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based.
Management
maintains internal controls designed to provide reasonable assurance that the estimates of proved reserves are computed and reported
in accordance with rules and regulations as promulgated by the SEC. The Company retained Pinnacle Energy Services, LLC (“Pinnacle”)
to independently prepare estimates of our oil and gas reserves in our properties in Logan County, Oklahoma. Management is responsible
for providing the following information related to our oil and gas properties to the firm: working and net revenue interests,
historical production rates, current operating and future development costs, and geoscience, engineering and other information.
Greg Franklin, our Chief Geologist, reviews the final reserve estimate for completeness and reasonableness and, if necessary,
discusses the process used and findings with the designated technical person at Pinnacle. Our Chief Geologist has over 25 years
of oil and gas experience. The technical person primarily responsible for audit of our reserve estimates at Pinnacle meets the
requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to
the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Pinnacle is
an independent firm of petroleum engineers, geologists, geophysicists, and petro physicists; they do not own an interest in our
properties and are not employed on a contingent fee basis. Reserve estimates are imprecise and subjective and may change at any
time as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering
data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production.
The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation
and judgment.
The
Company’s estimated future net recoverable oil and gas reserves from proved reserves, both developed and undeveloped properties,
were assembled by Pinnacle for the properties in Logan County, Oklahoma as of December 31, 2013 and December 31, 2012, and are
as follows:
| | |
| | |
| | |
Natural | |
| | |
Crude | | |
Natural | | |
Gas | |
| | |
Oil | | |
Gas | | |
Liquids | |
| | |
(BBLs) | | |
(MCF) | | |
(BBLs) | |
| December
31, 2013 | |
| 1,508,000 | | |
| 6,365,000 | | |
| 43,000 | |
| | |
| | | |
| | | |
| | |
| December
31, 2012 | |
| 364,000 | | |
| 1,499,000 | | |
| - | |
Using
year-end oil, gas and natural gas liquid prices and lease operating expenses, the estimated value of future net revenues to be
derived from the Company’s proved developed oil and gas reserves, discounted at 10%, were approximately $40.9 million at
December 31, 2013 and $14.8 million at December 31, 2012 for the Properties in Logan County, Oklahoma.
As of December 31, 2013, the
Company had estimated proved developed and proved undeveloped reserves of crude oil of 460,000 BBLs and 1,048,000 BBLS,
respectively, estimated proved developed and proved undeveloped reserves of natural gas of 2,005,000 Mcf and 4,360,000 Mcf,
respectively, and estimated proved developed and proved undeveloped reserves of natural gas liquids of 33,000 BBLs and 10,000
BBLs, respectively. All changes in estimated proved developed and proved undeveloped reserves during 2013 were as a result
of extensions and discoveries. In December 2011, the Company commenced drilling its first development well in Logan County
and incurred $17,891,932 during 2013 in capital expenditures for oil and gas related properties (including $3,261,096 in
converting proved updeveloped reserves to proved developed reserves). We participated in the drilling and completion of 35 productive
development wells during 2013 and had participated in the drilling and completion of 40 productive development wells as of
December 31, 2013.
During 2013 we converted 127,621
BBLs of crude oil and 491,556 Mcf of natural gas from proved undeveloped reserves to proved developed reserves as a result of
capital expenditures of $3,261,096 and added 1,006,621 BBLs of crude oil, 4,155,556 Mcf of natural gas and 10,000 BBLs of
natural gas liquids to proved undeveloped reserves through extension and discovery.
As of December 31, 2013, the Company had no estimated proved
undeveloped reserves that had remained undeveloped for more than five years, and we expect to develop all estimated proved
undeveloped reserves within five years of the date of original booking.
The
Company’s net oil production after other working interests and average cost per barrel for 2013 and 2012 were as follows:
| | |
2013 | | |
2012 | | |
Increase/(Decrease) | |
| Oil
Production: | |
| Net
Barrels | | |
| %
of Total | | |
| Net
Barrels | | |
| %
of Total | | |
| Barrels | | |
| % | |
| United
States | |
| 76,409 | | |
| 100.0 | % | |
| 22,057 | | |
| 100.0 | % | |
| 54,352 | | |
| 246.4 | % |
The
Company’s average production cost per barrel of oil equivalent is as follows:
| | |
2013 | | |
2012 | |
| | |
| | |
| |
| Average
production cost per barrel of oil equivalent (“BOE”) | |
$ | 14.76 | | |
$ | 7.26 | |
The
following summarizes the developed leasehold acreage held by the Company as of December 31, 2013 and 2012. Gross acres are the
total number of acres in which the Company has a working interest. Net acres are the sum of the Company’s fractional interests
owned in the gross acres. Developed acreage is acreage in which we have leased the mineral rights for oil and gas and have drilled
or re-worked wells. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit
the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
| | |
Developed
Acreage | |
| | |
Gross | | |
Net | |
| December
31, 2013 | |
| 26,823 | | |
| 4,181 | |
| | |
| | | |
| | |
| December
31, 2012 | |
| 2,821 | | |
| 651 | |
| | |
Undeveloped Acreage | |
| | |
Gross | | |
Net | |
| December 31, 2013 | |
| 24,328 | | |
| 13,457 | |
| | |
| | | |
| | |
| December 31, 2012 | |
| 59,240 | | |
| 14,845 | |
The
following summarizes the Company’s productive oil wells as of December 31, 2013 and 2012. Productive wells are producing
wells and wells capable of production. Gross wells are the total number of wells in which the Company has an interest. Net wells
are the sum of the Company’s fractional interests owned in the gross wells.
| | |
Productive
Wells | |
| | |
Gross | | |
Net | |
| December 31, 2013 | |
| 40.0 | | |
| 7.2 | |
| | |
| | | |
| | |
| December 31, 2012 | |
| 5.0 | | |
| 1.1 | |
All of the Company’s
wells are productive development wells and, as of December 31, 2013 and 2012, the Company had no dry development wells, nor any
productive nor dry exploratory wells.
Drilling
Activity
In
December 2011, the Company commenced drilling its first well in Logan County and at December 31, 2013 the Company had commenced
drilling 42 wells, 40 of which achieved production and revenues in 2013. During 2013, we participated in the drilling of 35
gross productive wells (6.1 net wells) and 2 gross wells (0.3 net wells) which had not yet achieved production as of December
31,2013. During 2012, we participated in the drilling of 5 gross productive wells (1.1 net wells) and 3 gross wells (0.6 net wells)
which had not yet achieved production as of December 31, 2012. Also as of December 31, 2013, the Company had completed four
salt water disposal wells.
Delivery
Commitments
We
are obligated, under certain open oil and natural gas derivative positions to deliver monthly, through June 30, 2015, 6,000 BBLs
of oil and 10,000 Mcf of natural gas.
Item
3. Legal Proceedings
Neither
our Company nor any of its property is a party to, or the subject of, any material pending legal proceedings other than ordinary,
routine litigation incidental to our business.
Item
4. Mine Safety Disclosures
Not
applicable.
PART
II
Item
5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our
common stock trades on the OTC Bulletin Board under the symbol “OEDV”. The high and low closing prices, as reported
by the OTC Bulletin Board, are as follows for 2013 and 2012. The quotations reflect inter-dealer prices, without retail mark-up,
mark-down or commission and may not represent actual transactions.
| |
High | | |
Low | |
| Year ended December 31, 2013 | |
| | |
| |
| First Quarter | |
$ | 1.85 | | |
$ | 0.91 | |
| Second Quarter | |
$ | 1.60 | | |
$ | 1.05 | |
| Third Quarter | |
$ | 1.58 | | |
$ | 0.90 | |
| Fourth Quarter | |
$ | 1.49 | | |
$ | 0.96 | |
| | |
| | | |
| | |
| Year ended December 31, 2012 | |
| | | |
| | |
| First Quarter | |
$ | 1.07 | | |
$ | 0.40 | |
| Second Quarter | |
$ | 2.37 | | |
$ | 0.70 | |
| Third Quarter | |
$ | 1.39 | | |
$ | 0.95 | |
| Fourth Quarter | |
$ | 1.11 | | |
$ | 0.55 | |
Dividends
We
have declared no cash dividends on our common stock since inception. There are no restrictions that limit our ability to pay dividends
on our common stock or that are likely to do so in the future other than the restrictions set forth in Section 170(b) of the Delaware
General Corporation Law that provides that a company may declare and pay dividends upon the shares of its capital stock either
(1) out of its surplus, as defined in and computed in accordance with Sections 154 and 244 of the Delaware General Corporation
Law, or (2) in case there shall be no such surplus, out of its net profits for the fiscal year in which the dividend is declared
and/or the preceding fiscal year. We have not declared, paid cash dividends, or made distributions in the past. We do not anticipate
that we will pay cash dividends or make distributions in the foreseeable future. We currently intend to retain and reinvest future
earnings to finance operations.
Securities
Authorized for Issuance Under Equity Compensation Plans
In
June 2007, we implemented the 2007 Osage Exploration and Development, Inc. Equity-Based Compensation Plan (the “Plan”)
which allows the reservation of 5,000,000 shares under the Plan. Under this Plan, securities issued may include options, stock
appreciation rights (“SARs”) and restricted stock. No securities have yet been issued under this plan since inception.
Holders
As
of March 27, 2014, there were approximately 220 holders of record of our common stock, which figure does not take into account
those stockholders whose certificates are held in the name of broker-dealers or other nominee accounts.
Issuer
Purchase of Equity Securities
None.
Item
6. Selected Financial Data
Not
Applicable.
Item
7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
This
report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of
the Securities Exchange Act of 1934 that include, among others, statements of: expectations, anticipations, beliefs, estimations,
projections, and other similar matters that are not historical facts, including such matters as: future capital requirements,
development and exploration expenditures (including the amount and nature thereof), drilling of wells, reserve estimates (including
estimates of future net revenues associated with such reserves and the present value of such future net revenues), future production
of oil and gas, repayment of debt, business strategies, and expansion and growth of business operations. These statements are
based on certain assumptions and analyses made by our management in light of past experience and perception of: historical trends,
current conditions, expected future developments, and other factors that our management believes are appropriate under the circumstances.
We caution the reader that these forward-looking statements are subject to risks and uncertainties, including those associated
with the financial environment, the regulatory environment, and trend projections, that could cause actual events or results to
differ materially from those expressed or implied by the statements. Such risks and uncertainties include those risks and uncertainties
identified below.
Significant
factors that could prevent us from achieving our stated goals include: declines in the market prices for oil and gas, adverse
changes in the regulatory environment affecting us, the inherent risks involved in the evaluation of properties targeted for acquisition,
our dependence on key personnel, the availability of capital resources at terms acceptable to us, the uncertainty of estimates
of proved reserves and future net cash flows, the risk and related cost of replacing produced reserves, the high risk in exploratory
drilling and competition. You should consider the cautionary statements contained or referred to in this report in connection
with any subsequent written or oral forward-looking statements that may be issued. We undertake no obligation to release publicly
any revisions to any forward-looking statement to reflect events or circumstances after the date hereof or to reflect the occurrence
of unanticipated events.
On April 8, 2008, we entered
into a membership interest purchase agreement (the “Purchase Agreement”) with Sunstone Corporation (“Sunstone”)
pursuant to which we acquired from Sunstone 100% of the membership interests in Cimarrona Limited Liability Company, an Oklahoma
limited liability company (“Cimarrona LLC”). Cimarrona LLC owns a 9.4% interest in certain oil and gas assets in the
Guaduas field, located in the Dindal and Rio Seco Blocks that consist of 21 wells, of which seven are currently producing, that
covers 30,665 acres in the Middle Magdalena Valley in Colombia as well as a pipeline with a current capacity of approximately
40,000 barrels of oil per day. The Purchase Agreement was effective as of April 1, 2008. The Cimarrona property is subject to
an Ecopetrol Association Contract (the “Association Contract”) whereby we pay Ecopetrol S.A. (“Ecopetrol”)
royalties of 20% of the oil produced. The pipeline is not subject to the Association Contract. The royalty amount for the Cimarrona
property is paid in oil. The property and the pipeline are both operated by Pacific, which owns 90.6% of the Guaduas field. Pipeline
revenues generated from the Cimarrona property primarily relate to transportation costs charged to third party oil producers,
including Pacific.
On October 7, 2013, the Company
completed the sale of 100% of the membership interests in Cimarrona LLC to Raven Pipeline Company, LLC (“Raven”),
pursuant to a Membership Interest Purchase Agreement (the “Agreement”) dated September 30, 2013 by and between the
Company and Raven. Accordingly, the Company will not recognize any revenues or expenses for Cimarrona LLC from October 1, 2013.
The sales price consisted of cash of $6,800,000, less settlement of debt of Cimarrona LLC of approximately $250,000. Of the net
sales price, $250,000 will be held in escrow for 12 months to secure any post-closing purchase price adjustments and any indemnity
obligations of the Company pursuant to the Agreement. In addition, so long as the per barrel transportation rate charged with
respect to the pipeline is not adjusted prior to March 31, 2014, then Raven will pay the Company an additional $1,000,000 in cash
within five business days of that date.
In
2010, we began to acquire oil and gas leases in Logan County, Oklahoma targeting the Mississippian formation. The Mississippian
formation is located on the Anadarko Shelf in northern Oklahoma and south-central Kansas. The top of this expansive carbonate
hydrocarbon system is encountered between 4,000 and 6,000 feet and lies stratigraphically between the Pennsylvanian-aged Morrow
Sand and the Devonian-aged Woodford Shale formations. The Mississippian formation may reach 600 feet in gross thickness and the
targeted porosity zone is between 50 and 300 feet in thickness. The formation’s geology is well understood as a result of
the thousands of vertical wells drilled and produced there since the 1940s. Beginning in 2007, the application of horizontal cased-hole
drilling and multi-stage hydraulic fracturing treatments have demonstrated the potential for extracting significant additional
quantities of oil and natural gas from the formation.
On
April 21, 2011, the Company entered into a participation agreement (“Participation Agreement”) with Slawson Exploration
Company (“Slawson”) and U.S. Energy Development Corporation (“USE,” Slawson and USE, together, the “Parties”).
Pursuant to the terms of the Participation Agreement, Slawson and USE acquired 45% and 30% respectively, of our 10,000 acre Nemaha
Ridge prospect in Logan County, Oklahoma for $4,875,000. In addition, the Parties carried Osage for 7.5% of the cost of the first
three horizontal Mississippian wells, which means that for the first three horizontal Mississippian wells, the Company provided
up to 17.5% of the total well costs. After the first three wells, the Company is responsible for up to 25% of the total well costs.
Revenue from wells drilled pursuant to the Participation Agreement, after royalty payments, is allocated 45% to Slawson, 30% to
USE and 25% to Osage. Slawson was the operator of all wells in the Nemaha Ridge prospect in sections where the Parties’
acreage controlled the section. In sections where the Parties’ acreage did not control the section, we may elect to participate
in wells operated by others.
On
December 12, 2013, Osage and Slawson entered into an agreement (the “Partition Agreement”) which amended Participation
Agreement related to certain lands located within the Nemaha Ridge in Logan County, Oklahoma, and for the exploration and development
of those leases by the Parties.
Under
the Partition Agreement and effective as of September 1, 2013, the Slawson Exploration Group agreed to assign all of its rights,
title and interest in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within
certain sections to Osage and Osage agreed to assign all of its rights, title and interest in and to the oil and gas leases and
force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to the Slawson Exploration Group, such
that the net acreage controlled by the parties would remain substantially unchanged, but that the acreage controlled by each of
the parties in undeveloped sections would be located in sections where the other party did not control acreage. The parties also
agreed that the Participation Agreement would terminate as to all lands within the Nemaha Ridge Project except for lands within
sections already developed by the parties which shall continue to be controlled by the Participation Agreement.
As
a result of the Partition Agreement, Osage has become the project operator on a majority of its acreage in the Nemaha Ridge Project.
As of December 31, 2013, Osage was allocated approximately 5,014 net acres (9,734 gross) in thirty sections, and remains joint-venture
partners with the Slawson in approximately 4,181 net acres (26,823 gross) across forty-five sections.
In
2011, the Company began to acquire leases in Pawnee County, Oklahoma, targeting the Mississippian formation. In July 2011, we
purchased from B&W Exploration, Inc. (“B&W”) the Pawnee County prospect targeting the Mississippian, for $8,500.
In addition, B&W is also entitled to an overriding royalty interest on the leases acquired and a 12.5% carry on the first
$200,000 of lease bonus paid in the form of an assignment of 12.5% of the leases acquired. Subsequently,
B&W shall have an option to purchase a 12.5% share of leasehold acquired on a heads-up basis.
As of December 31, 2013, the Company had 4,190 net acres (5,085 gross) leased in Pawnee County. As of December 31, 2013, none
of these leases have been assigned to B&W.
In
2011, we also began to acquire leases in Coal County, Oklahoma, targeting the Woodford Shale formation. The Woodford Shale formation
is located mainly in southeastern Oklahoma in the Arkoma Basin. The Woodford shale lies directly under the Mississippian and started
as a vertical play, but horizontal drilling techniques and multi-stage fracturing technology have been used in the Woodford in
recent years with much success. At December 31, 2013, we had 4,253 net (9,509 gross) acres leased in Coal County.
At
December 31, 2013, we have leased 51,151 gross (17,638 net) acres across three counties in Oklahoma as follows:
| | |
Gross | | |
Osage Net | |
| Logan (non operated) | |
| 26,823 | | |
| 4,181 | |
| Logan | |
| 9,734 | | |
| 5,014 | |
| Coal | |
| 9,509 | | |
| 4,253 | |
| Pawnee | |
| 5,085 | | |
| 4,190 | |
| | |
| 51,151 | | |
| 17,638 | |
The
Company has accumulated deficits of $4,219,480 and $8,074,786 and working capital deficits of $12,961,622 and $643,843 as of December
31, 2013 and 2012, respectively.
The
Company’s operating plans require additional funds which may take the form of debt or equity financings. The Company’s
ability to continue as a going concern is in substantial doubt and is dependent upon achieving profitable operations and obtaining
additional financing. There is no assurance additional funds will be available on acceptable terms or at all.
Management
of the Company has undertaken steps as part of a plan to improve operations with the goal of sustaining our operations for the
next 12 months and beyond. These steps include (a) BECOMING OPERATORS OF OUR OWN WELLS,
(B) participating in drilling of wells in Logan County, Oklahoma within the next 12 months, (c) controlling overhead and
expenses, and (d) raising additional equity and/or debt.
On
April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement with Apollo Investment Corporation and on
April 5, 2013 we amended this agreement, increasing the facility to $20,000,000. As of December 31, 2013, as a result of production
delays outside of the Company’s control, the Company was not in compliance with certain covenants including the minimum
production covenant under the senior secured note purchase agreement. (see Note 6 - Debt in the accompanying consolidated financial
statements).
In
February 2014, the Company initiated a private placement, pursuant to Securities Purchase Agreements between Osage and certain
purchasers, with aggregate gross proceeds of approximately $6.5 million. The purchase price of each unit, representing one share
of common stock and a warrant to purchase 0.4 shares of common stock at $1.80 per share, was $0.90. The warrants have a term of
five years. The placement agent will receive placement fees of 8%, in cash or warrants or a combination thereof at their election.
The
Company’s operating plans require additional funds which may take the form of debt or equity financings. The Company’s
ability to continue as a going concern is in substantial doubt and is dependent upon achieving profitable operations and obtaining
additional financing. There is no assurance additional funds will be available on acceptable terms or at all. In the event we
are unable to continue as a going concern, we may elect or be required to seek protection from our creditors by filing a voluntary
petition in bankruptcy or may be subject to an involuntary petition in bankruptcy.
Results
of Operations
Year
ended December 31, 2013 compared to year ended December 31, 2012
| | |
2013 | | |
2012 | | |
Change | |
| | |
Amount | | |
Percentage | | |
Amount | | |
Percentage | | |
Amount | | |
Percentage | |
| Revenues | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| Oil sales | |
$ | 7,339,943 | | |
| 91.4 | % | |
$ | 2,030,596 | | |
| 89.7 | % | |
| $
5,309,347 | | |
| 261.5 | % |
| Natural gas sales | |
| 6
89,145 | | |
| 8.6 | % | |
| 233,417 | | |
| 10.3 | % | |
| 455,728 | | |
| 195.2 | % |
| Total revenues | |
$ | 8,029,088 | | |
| 100.0 | % | |
$ | 2,264,013 | | |
| 100.0 | % | |
$ | 5,765,075 | | |
| 254.6 | % |
Oil
Sales
Oil
sales were $7,339,943, in 2013, an increase of $5,309,347, or 261.5%, compared to $2,030,596 in 2012. The increase in oil sales
is due to additional wells in production in Logan County, Oklahoma. We sold 74,567 barrels (“BBLs”) in 2013 at an
average gross price of $97.31 per barrel, compared to 22,146 BBLs in 2012 at an average price of $94.13 per barrel.
Natural
Gas Sales
Natural
gas sales comprise revenues from the sale of natural gas and natural gas liquids. Natural gas sales were $689,145 for the year
ended December 31, 2013 compared to $233,417 for the year ended December 31, 2012. All of our natural gas sales are from the well
production in Logan County, Oklahoma. Natural gas production is measured in a 1,000 cubic foot unit referred to as a “Mcf.”
and natural gas liquid production is measured in BBLs. We sold 141,506 Mcf of natural gas at an average of $3.97 per Mcf in 2013
compared to 50,430 Mcf at $4.74 per Mcf in 2012. The price achieved per BBL for 3,306 BBLs of natural gas liquids in 2013 was
$28.88 and there were no sales of natural gas liquids in 2012.
Total
Revenues
Total
revenues were $8,029,088, an increase of $5,765,075, or 254.6% for the year ended December 31, 2013 compared to $2,264,013 for
the year ended December 31, 2012. Oil sales accounted for 91.4% and 89.7% of total revenues in the 2013 and 2012 periods, respectively.
Production
| | |
2013 | | |
2012 | | |
Increase/(Decrease) | |
| Oil Production: | |
Net Barrels | | |
% of Total | | |
Net Barrels | | |
% of Total | | |
Barrels | | |
% | |
| United States | |
| 76,409 | | |
| 100.0 | % | |
| 22,057 | | |
| 100.0 | % | |
| 54,352 | | |
| 246.4 | % |
| | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| Natural Gas Production: | |
Mcf | | |
% of Total | | |
Mcf | | |
% of Total | | |
Mcf | | |
% | |
| United States | |
| 149,738 | | |
| 100.0 | % | |
| 62,131 | | |
| 100.0 | % | |
| 87,607 | | |
| 141.0 | % |
| | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| Natural Gas
Liquid Production: | |
Net
Barrels | | |
%
of Total | | |
Net
Barrels | | |
%
of Total | | |
Barrels | | |
% | |
| United States | |
| 3,507 | | |
| 100.0 | % | |
| - | | |
| n/a | | |
| 3,507 | | |
| n/a | |
Oil
production, net of royalties, was 76,409 BBLs, an increase of 54,352 BBLs, or 246.4%, for the year ended December 31, 2013 compared
to 22,057 BBLs for the year ended December 31, 2012, due to production increases as a result of additional wells.
Natural
gas production was 149,738 Mcf, an increase of 87,607 Mcf, or 141.0%, for the year ended December 31, 2013, compared to 62,131
Mcf for the year ended December 31, 2012.
Natural
gas liquid production for the year ended December 31, 2013 was 3,507 BBLs and there was no production of natural gas liquids in
the prior year.
Operating
Costs and Expenses
| | |
2013 | | |
2012 | | |
Change | |
| | |
| | |
Percent of | | |
| | |
Percent of | | |
| | |
| |
| | |
Amount | | |
Sales | | |
Amount | | |
Sales | | |
Amount | | |
Percentage | |
| Operating Expenses | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| Operating expenses | |
| $
1 ,547,949 | | |
| 19.3 | % | |
| $
2 58,686 | | |
| 11.4 | % | |
| $
1 ,289,263 | | |
| 498.4 | % |
| General & administrative expenses | |
| 2,613,920 | | |
| 32.6 | % | |
| 2
,661,922 | | |
| 117.6 | % | |
| (48,002 | ) | |
| -1.8 | % |
| Depreciation, depletion and accretion | |
| 2,320,441 | | |
| 28.9 | % | |
| 3
14,540 | | |
| 13.9 | % | |
| 2
,005,901 | | |
| 637.7 | % |
| Loss on disposal of fixed assets | |
| - | | |
| n/a | | |
| 21,599 | | |
| 1.0 | % | |
| (21,599 | ) | |
| n/a | |
| Total operating expenses | |
| $
6,482,310 | | |
| 80.7 | % | |
| $
3 ,256,747 | | |
| 143.8 | % | |
| $
3 ,225,563 | | |
| 99.0 | % |
| | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| Operating income (loss) | |
$ | 1,546,778 | | |
| 19.3 | % | |
$ | (992,734 | ) | |
| -43.8 | % | |
$ | 2,539,512 | | |
| -255.8 | % |
Well
operating expenses
Our
well operating expenses in 2013 were $1,547,949, an increase of $1,289,263, or 498.4% compared to $258,686 in 2012, due primarily
to an increase in the number of wells in operation in Logan County, Oklahoma. Operating expenses as a percentage of total revenues
increased to 19.3% in 2013 from 11.4% in 2012, as the percentage increase in operating expenses was greater than the percentage
increase in revenues as new wells came into production. Production Cost/BOE for 2013 was $14.76 compared to $7.26 for 2012.
General
and administrative expenses
General
and administrative expenses in 2013 were $2,613,920, a decrease of $48,002, or 1.8%, compared to $2,661,922 in 2012. The decrease
is primarily due to a reduction in stock based compensation of $368,277 to $528,417 in 2013 and a reduction in legal and professional
fees of $104,427 to $406,513 in 2013, partially offset by an increase in salaries of $242,938 to $932,380 in 2013 and an increase
in insurance of $70,711 to $176,478 in 2013. As a percentage of revenues, general and administrative expenses reduced to 32.6%
in 2013 from 117.6% in 2012.
Depreciation,
depletion and accretion
Depreciation,
depletion and accretion were $2,320,411 for the year ended December 31, 2013 and $314,540 for the year ended December 31, 2012,
an increase of $2,005,901 or 637.7%, due to increased wells in production. Our depletion expense will continue to increase to
the extent we are successful in our well production in Oklahoma.
Operating
income (loss)
Operating
income was $1,546,778 in 2013 compared to an operating loss of $992,734 in 2012. The improvement in operating results of $2,539,512
was due to the increase in revenues of $5,765,075 for the year ended December 31, 2013 compared to the year ended December 31,
2012, partially offset by the $3,225,563 increase in operating expenses during the same period.
Interest
expense
Interest
expense was $4,566,246 for the year ended December 31, 2013 compared to $1,390,277 for the year ended December 31, 2012, an increase
of $3,175,969. The increase in interest expense during the 2013 period was primarily due to increased borrowings with respect
to the Note Purchase Agreement. Cash interest expense in 2013 amounted to $2,999,838, and non-cash interest expense in 2013 of
$1,566,408 was comprised of amortization of deferred financing fees of $1,295,348 in connection with the Note Purchase Agreement
and amortization of debt discount of $271,060 with respect to the Secured Promissory Note.
Oil
and gas derivatives
Oil
and gas derivatives reflected an unrealized loss of $357,567 for the year ended December 31, 2013 as a result of marking open
financial derivative instruments to market as of December 31, 2013 and losses realized on financial derivative instruments settled
of $138,236 during the year then ended. There were no open financial derivative instruments as of December 31, 2012.
Provision
for income taxes
Provision
for income taxes was $1,624 for 2013 and zero for 2012. The 2013 provision represented minimum state corporation tax assessments.
Loss
from continuing operations
Loss
from continuing operations was $3,514,895 for the year ended December 31, 2013 compared to a loss of $2,380,133 for the year ended
December 31, 2012. The $2,539,512 increase in operating income was more than offset by the $3,175,969 increase in interest expense
and the $495,803 loss on oil and gas derivatives in the year ended December 31, 2013 compared to the prior year period.
Income
from discontinued operations net of income taxes
Income
from discontinued operations net of income taxes was $2,496,541 in the year ended December 31, 2013 compared to income of $1,863,427
in the prior year period. The income in 2013 represents income for the nine months ended September 30, 2013, the effective date
of the sale of the discontinued operations, and includes a benefit of $531,644 related to an amnesty for certain 2003 equity taxes.
Gain
on disposal of discontinued operations
The
Company recorded a gain of $4,873,660 on the sale of Cimarrona, LLC which comprised certain oil and pipeline assets and operations
in Colombia.
Net
income (loss)
Net
income was $3,855,306 in 2013 compared to a net loss of $516,706 in 2012. The increase in loss from continuing operations of $1,134,762
was more than offset by the increase in income from discontinued operations after taxes of $633,114 and the gain on the sale of
discontinued operations of $4,873,660 when comparing 2013 to 2012.
Foreign
currency translation adjustment attributable to discontinued operations
Foreign
currency translation gain was $24,153 in 2013 compared to a loss of $21,460 in 2012, as a result of favorable trends in the Colombian
Peso to Dollar exchange rate.
Comprehensive
income (loss)
Comprehensive
income was $3,879,459 for the year ended December 31, 2013 compared to a comprehensive loss of $538,166 for the year ended December
31, 2012. The increase in net income of $4,372,012 to $3,855,306 in 2013 from a loss in 2012 was the primary contributor, along
with the foreign currency translation gain of $24,153 compared to a loss of $21,460 in 2012.
Income
(loss) per share
Basic
and diluted loss per share from continuing operations was $0.07 in 2013 compared to a loss per share of $0.05 in 2012. Basic and
diluted income per share from discontinued operations in 2013 was $0.15, compared to $0.04 in 2012, primarily due to the gain
of $4,873,660 on the sale of discontinued operations.
Liquidity
and Capital Resources
We
had a working capital deficit of $12,961,622 at December 31, 2013, compared to working capital deficit of $643,843 at December
31, 2012. The increase in the working capital deficit is primarily as a result of the $17,000,000 increase in notes payable, partially
offset by the $2,296,438 increase in cash and equivalents.
Net
cash provided by operating activities was $80,491 in 2013 compared to $1,962,071 in 2012. The major components of net cash provided
by operating activities in 2013 were the $3,855,306 net income, the $2,320,213 provision for depreciation, depletion and accretion
and the $1,295,348 amortization of deferred financing costs almost fully offset by the gain on sale of oil & gas properties
of $4,873,660, the increase of $2,660,855 in accounts receivable and the decrease of $1,267,320 in accrued expenses. The major
components of net cash provided by operating activities in 2012 were the $568,777 provision for depreciation, depletion and accretion,
the amortization of deferred financing costs of $734,976, the
increase in accrued expenses of $687,887 and warrants and
shares issued for services of $448,111 and $448,583, respectively, offset by the $516,706 net loss and the increase in accounts
receivable of $363,548.
Net
cash used by investing activities was $12,365,388 in 2013 compared to $8,098,036 in 2012. Net cash used by investing activities
in 2013 consisted primarily of $17,891,932 investment in oil & gas properties, partially offset by $6,295,193 net proceeds
from the sale of oil & gas properties. Net cash used by investing activities in 2012 consisted primarily of $12,781,375 investment
in oil & gas properties, partially offset by $4,686,610 net proceeds from assignment of leases.
Net
cash provided by financing activities was $14,552,815 and $4,831,308 in 2013 and 2012, respectively. Net cash provided in 2013
consisted primarily of proceeds of $17,000,000 from secured promissory notes, partially offset by $2,500,000 in principal repayments
on secured promissory notes. Net cash provided in 2012 consisted primarily of $5,500,000 of borrowing on secured promissory notes,
partially offset by payment of $670,692 of deferred financing costs.
Net
operating revenues from our oil production are very sensitive to changes in the price of oil making it very difficult for management
to predict whether or not we will be profitable in the future.
We
conduct no product research and development. Any expected purchase of significant equipment is directly related to drilling operations
and the completion of successful wells.
We
are responsible for any contamination of land we own or lease. However, we carry pollution liability insurance policies, which
may limit some potential contamination liabilities as well as claims for reimbursement from third parties.
Item
7A. Quantitative and Qualitative Disclosures about Market Risk
We
have material exposure to interest rate changes, as our $20,000,000 secured promissory note carries an interest rate of the London
interbank overnight rate (“Libor”) plus 15%, with a Libor floor of 2%. We are subject to changes in the price of oil,
which are out of our control. At our Oklahoma Properties, we sold oil at $88.90 to $106.32 per barrel in 2013 compared to $79.79
to $106.49 per barrel in 2012.
Effect
of Changes in Prices
Changes
in prices during the past few years have been a significant factor in the oil and gas industry. The price received for the oil
produced by us fluctuated significantly during the last year. Changes in the price that we receive for our oil and natural gas
is set by market forces beyond our control as well as governmental intervention. The volatility and uncertainty in oil and natural
gas prices have made it more difficult for a company like us to increase our oil and natural gas asset base and become a significant
participant in the oil and gas industry. We currently sell the majority our oil and natural gas production to Slawson, Stephens
and Devon. However, in the event these customers discontinued oil and gas purchases, we believe we can replace them with other
customers which would purchase the oil and gas at terms standard in the industry.
Critical
Accounting Policies and Estimates
Management’s
Discussion and Analysis of Financial Condition and Results of Operations discusses our consolidated financial statements, which
have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation
of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets
and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting
period. On an on-going basis, management evaluates our estimates and judgments, including those related to revenue recognition,
recovery of oil and gas reserves, financing operations, and contingencies and litigation.
Oil
and Gas Properties
We
follow the “successful efforts” method of accounting for our oil and gas exploration and development activities, as
set forth in the Statement of Financial Accounting Standards (SFAS) No. 19, as codified by FASB ASC topic 932. Under this method,
we initially capitalize expenditures for oil and gas property acquisitions until they are either determined to be successful (capable
of commercial production) or unsuccessful. The carrying value of all undeveloped oil and gas properties is evaluated periodically
and reduced if such carrying value appears to have been impaired. Leasehold costs relating to successful oil and gas properties
remain capitalized while leasehold costs which have been proven unsuccessful are charged to operations in the period the leasehold
costs are proven unsuccessful. Costs of carrying and retaining unproved properties are expensed as incurred.
The
costs of drilling and equipping development wells are capitalized, whether the wells are successful or unsuccessful. The costs
of drilling and equipping exploratory wells are capitalized until they are determined to be either successful or unsuccessful.
If the wells are successful, the costs of the wells remain capitalized. If, however, the wells are unsuccessful, the capitalized
costs of drilling the wells, net of any salvage value, are charged to operations in the period the wells are determined to be
unsuccessful.
The
provision for depreciation and depletion of oil and gas properties is computed on the unit-of-production method. Under this method,
we compute the provision by multiplying the total unamortized costs of oil and gas properties including future development, site
restoration, and dismantlement abandonment costs, but excluding costs of unproved properties by an overall rate determined by
dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves.
This calculation is done on a field-by-field basis. As of December 31, 2013 and 2012, our oil and natural gas production continuing
operations were conducted in Logan County in the state of Oklahoma. The cost of unevaluated properties not being amortized, to
the extent there is such a cost, is assessed quarterly to determine whether the value has been impaired below the capitalized
cost. The cost of any impaired property is transferred to the balance of oil and gas properties being depleted. The costs associated
with unevaluated properties relate to projects which were undergoing exploration or development activities or in which we intend
to commence such activities in the future. We will begin to amortize these costs when proved reserves are established or impairment
is determined.
In
accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” as codified by FASB ASC topic 410, we
report a liability for any legal retirement obligations on our oil and gas properties. The asset retirement obligations represent
the estimated present value of the amounts expected to be incurred to plug, abandon, and remediate the producing properties at
the end of their productive lives, in accordance with state laws, as well as the estimated costs associated with the reclamation
of the property surrounding. The Company determines the asset retirement obligations by calculating the present value of estimated
cash flows related to the liability. The asset retirement obligations are recorded as a liability at the estimated present value
as of the asset’s inception, with an offsetting increase to producing properties. Periodic accretion of the discount related
to the estimated liability is recorded as an expense in the statement of operations.
The
estimated liability is determined using significant assumptions, including current estimates of plugging and abandonment costs,
annual inflation of these costs, the productive lives of wells, and a risk-adjusted interest rate. Changes in any of these assumptions
can result in significant revisions to the estimated asset retirement obligations. Revisions to the asset retirement obligations
are recorded with an offsetting change to producing properties, resulting in prospective changes to depletion and depreciation
expense and accretion of the discount. Because of the subjectivity of assumptions and the relatively long lives of most of the
wells, the costs to ultimately retire the Company’s wells may vary significantly from prior estimates.
Revenue
Recognition
We
recognize revenue upon transfer of ownership of the product to the customer which occurs when (i) the product is physically received
by the customer, (ii) an invoice is generated which evidences an arrangement between the customer and us, (iii) a fixed sales
price has been included in such invoice and (iv) collection from such customer is probable.
We
recognize sales from our properties using the sales method. Under the sales method, the working interest owners recognize sales
of oil and gas regardless of the amount produced for the period. The sales method assumes that any production sold by a working
interest owner comes from that party’s share of the total reserves in place. Thus, whatever quantity is sold in any given
period is the revenue for that party. No receivables, payables or unearned revenue are recorded unless a working interest owner’s
aggregate sales from the property exceed its share of the total reserves in place.
Off-Balance
Sheet Arrangements
Our
Company has not entered into any transaction, agreement or other contractual arrangement with an entity unconsolidated with us,
except as disclosed in the consolidated financial statements, under which we have:
| ● | an
obligation under a guarantee contract, |
| | |
| ● | a
retained or contingent interest in assets transferred to the unconsolidated entity or
similar arrangement that serves as credit, liquidity or market risk support to such entity
for such assets, |
| | |
| ● | any
obligation, including a contingent obligation, under a contract that would be accounted
for as a derivative instrument, or |
| | |
| ● | any
obligation, including a contingent obligation, arising out of a variable interest in
an unconsolidated entity that is held by us and material to us where such entity provides
financing, liquidity, market risk or credit risk support to, or engages in leasing, hedging
or research and development services with us. |
Item
8. Financial Statements and Supplementary Data
Our
consolidated financial statements as of December 31, 2013 and for the year then ended were audited by Mayer Hoffman McCann P.C.
an independent registered accounting firm. Our consolidated financial statements as of December 31, 2012 and for the year then
ended were audited by MaloneBailey, LLP, an independent registered public accounting firm. These consolidated financial statements
have been prepared in accordance with generally accepted accounting principles pursuant to Regulation S-X as promulgated by the
SEC. The aforementioned consolidated financial statements are included herein starting with page F-1.
Item
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
In
January 2014 we dismissed MaloneBailey, LLP and appointed Mayer Hoffman McCann P.C. as our independent public accounting firm
for the 2013. There were no disagreements with either independent public accounting firm on accounting or financial disclosure.
Item
9A. Controls and Procedures
(a)
Disclosure Controls and Procedures.
The
Company’s management, including the Company’s principal executive officer and principal financial officer, evaluated
the effectiveness of the Company’s “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e)
promulgated under the Exchange Act. Based upon their evaluation, the principal executive officer and principal financial officer
concluded that, as of the end of the period covered by this report, the Company’s disclosure controls and procedures were
not effective for the purpose of ensuring that the information required to be disclosed in the reports that the Company files
or submits under the Exchange Act with the SEC (1) is recorded, processed, summarized and reported within the time periods specified
in the SEC’s rules and forms, and (2) is accumulated and communicated to the Company’s management, including its principal
executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.
(b)
Internal Controls Over Financial Reporting.
Management’s
Report on Internal Control Over Financial Reporting
The
management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting.
The internal control process has been designed under our supervision to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of the Company’s financial statements for external reporting purposes in accordance
with accounting principles generally accepted in the United States of America.
Management
conducted an assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31,
2013, utilizing a top-down, risk based approach described in SEC Release No. 34-55929 as suitable for smaller public companies.
Based on this assessment, management determined that the Company’s internal control over financial reporting as of December
31, 2013 is not effective. Based on this assessment, management has determined that, as of December 31, 2013, there were material
weaknesses in our internal control over financial reporting. The material weaknesses identified during management’s assessment
was the lack of independent oversight by an audit committee of independent members of the Board of Directors. As defined by the
Public Company Accounting Oversight Board Auditing Standard No. 5, a material weakness is a deficiency or a combination of deficiencies,
such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not
be prevented or detected. Given the difficulty of finding qualified individuals who are willing to serve as independent directors,
there has been no change in the audit committee.
Our
internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that accurately
and fairly reflect, in reasonable detail, transactions and dispositions of assets; and provide reasonable assurances that: (1)
transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles
generally accepted in the United States; (2) receipts and expenditures are being made only in accordance with authorizations of
management and the directors of the Company; and (3) unauthorized acquisitions, use, or disposition of the Company’s assets
that could have a material effect on the Company’s financial statements are prevented or timely detected.
All
internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to
be effective can provide only reasonable assurance with respect to financial statement preparations and presentations. Also, projections
of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes
in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
(c)
Changes to Internal Control Over Financial Reporting.
Except
as indicated herein, there were no changes in the Company’s internal control over financial reporting during the quarter
ending December 31, 2013 that have materially affected, or are reasonable likely to materially affect, the Company’s internal
control over financial reporting.
ITEM
9B. Other Information
None
PART
III
Item
10. Directors, Executive Officers and Corporate Governance.
The
following table sets forth the names, ages, and offices held by our directors and executive officers:
| Name |
|
Position |
|
Director
Since |
|
Age |
| Kim
Bradford |
|
President,
Chief Executive Officer, Chairman of the Board |
|
February
2007 |
|
61 |
| Greg
Franklin |
|
Chief
Geologist, Director |
|
May
2005 |
|
57 |
| Norman
Dowling |
|
Chief
Financial Officer |
|
N/A |
|
51 |
A
list of current executive officers and directors appears above. The directors of the Company are elected annually by the stockholders.
The executive officers serve at the pleasure of the Board of Directors (“BOD”). The directors do not receive fees
or other remuneration for their services, but are reimbursed for their out-of-pocket expenses to attend board meetings.
The
principal occupation and business experience during at least the last five years for each of the present directors and executive
officers of the Company are as follows:
Kim
Bradford: Mr. Bradford was elected President and Chief Executive Officer of the Company in January 2007 and elected to
our board as Chairman effective February 2007. Mr. Bradford also served as our Chief Financial Officer and Secretary from January
2007 through November 2007. In September 2008, Mr. Bradford once again became our Chief Financial Officer through January 2013.
In August 2005, Mr. Bradford co-founded Catalyst Consulting Partners LLC, a California based consulting firm that advised publicly
traded companies and their management teams on executive search, shareholder communications, general media consulting, investor
relations, website design and other corporate matters. In 2001, Mr. Bradford co-founded Decision Capital Management, LLC, the
successor firm to Decision Capital Management LP, a Registered Investment Advisor firm which he founded in 1999. Prior to founding
Decision Capital, Mr. Bradford has been involved in the brokerage business for over 25 years, both as an employee of major Wall
Street firms, such as Merrill Lynch and Morgan Stanley, and as a principal in a NASD broker dealer firm specializing exclusively
in natural resource based investments, such as oil and gas and precious metals mining.
Greg
L. Franklin: Mr. Franklin has been our Chief Geologist since November 9, 2007 and a director of the Company since May
2005. Mr. Franklin previously served as a consultant to the Company in the role of a petroleum geologist since February 2005.
Mr. Franklin has 25 years of experience in the search, discovery, management and production of oil and gas. From March 1999 to
February 2005 Mr. Franklin was a staff geologist for Barbour Energy. Mr. Franklin’s previous experience includes positions
as Vice President for Gulf Coast Exploration and Development Company and geologist with Conoco. Mr. Franklin graduated with a
Bachelor of Science in Geology from Oklahoma State University in 1980.
Norman
Dowling: Mr. Dowling has been our part time Chief Financial Officer since January 2013. Since 2009, Mr. Dowling has been
providing senior financial consulting services to a range of entities in the retail, technology, and education sectors. Mr. Dowling
has over 20 years of finance experience, including four years as Executive Vice President and Chief Financial Officer of The Active
Network, Inc. (“Active”) from 2004 through 2008, during which time Active completed 23 acquisitions and three private
equity rounds raising over $165 million, and four years as Vice President Finance, at PETCO Animal Supplies, Inc. (“PETCO”)
from 1999 through 2004, during which time PETCO was taken private through a leveraged recapitalization and re-emerged as a public
company through an initial public offering. Mr. Dowling also served as Chief Financial Officer of Factory 2U Stores, Inc. and
CinemaStar Luxury Theatres, Inc. In addition to a number of other senior financial positions, Mr. Dowling’s experience includes
six years with Ernst & Young in audit assurance and management consultancy roles. Mr. Dowling holds a Bachelor of Commerce
degree from University College Dublin, Ireland.
Section
16(a) Beneficial Ownership Reporting Compliance
Section
16(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) requires our directors and officers,
and the persons who beneficially own more than ten percent of our common stock, to file reports of ownership and changes in ownership
with the SEC. Copies of all filed reports are required to be furnished to us pursuant to Rule 16a-3 promulgated under the Exchange
Act. Based solely on the reports received by us and on the representations of the reporting persons, we believe that all required
directors, officers and greater than ten percent shareholders complied with applicable filing requirements during the fiscal year
ended December 31, 2013.
Audit
Committee
We
do not have an Audit Committee, as our BOD during 2013 performed the same functions of an Audit Committee, such as: recommending
a firm of independent certified public accountants to audit the annual financial statements; reviewing the independent auditors
independence, the financial statements and their audit report; and reviewing management’s administration of the system of
internal accounting controls. None of our directors are independent and no current director would qualify as an independent financial
expert. We do not currently have a written audit committee charter or similar document.
Nominating
Committee
We
do not have a Nominating Committee or Nominating Committee Charter. Our BOD performed some of the functions associated with a
Nominating Committee. We have elected not to have a Nominating Committee at this time. However, our Board of Directors intends
to continually evaluate the need for a Nominating Committee.
Code
of Conduct
We
have a written code of conduct that governs all of our officers, directors, employees and contractors. The code of conduct relates
to written standards that are reasonably designed to deter wrongdoing and to promote:
| |
(1) |
Honest
and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional
relationships; |
| |
|
|
| |
(2) |
Full,
fair, accurate, timely and understandable disclosure in reports and documents that are
filed with, or submitted to, the Commission and in other public communications made
by
an issuer; |
| |
|
|
| |
(3) |
Compliance
with applicable governmental laws, rules and regulations; |
| |
|
|
| |
(4) |
The
prompt internal reporting of violations of the code to an appropriate person or persons identified in the code; and |
| |
|
|
| |
(5) |
Accountability
for adherence to the code. |
Involvement
in Certain Legal Proceedings
No
director, person nominated to become a director, executive officer, promoter or control persons of our Company has been involved
during the last ten years in any of the following events that are material to an evaluation of his ability or integrity:
| ● | Bankruptcy
petitions filed by or against any business of which such person was a general partner
or executive officer either at the time of the bankruptcy or within two years prior to
that time. |
| | | |
| ● | Conviction
in a criminal proceeding or being subject to a pending criminal proceeding (excluding
traffic violations and other minor offenses). |
| | | |
| ● | Being
subject to any order, judgment or decree, not subsequently reversed, suspended or vacated,
of any court of competent jurisdiction, permanently or temporarily enjoining, barring
or suspending or otherwise limiting his involvement in any type of business, securities
or banking activities, or |
| | | |
| ● | Being
found by a court of competent jurisdiction (in a civil action), the Securities and Exchange
Commission or the Commodities Futures Trading Commission to have violated a federal or
state securities or commodities law, and the judgment has not been reversed, suspended
or vacated. |
Compensation
Committee
We
currently do not have a compensation committee of the BOD. Until a formal committee is established, if at all, our entire Board
of Directors will review all forms of compensation provided to our executive officers, directors, consultants and employees including
stock compensation and loans.
Item
11. Executive Compensation
Executive
Officers
Our
current executive officers are as follows:
| Name | |
Age | |
Position |
| Kim Bradford | |
61 | |
President, Chief Executive Officer |
| Greg Franklin | |
57 | |
Chief Geologist |
| Norman Dowling | |
51 | |
Chief Financial Officer |
Pursuant
to Securities Exchange Commission rules, our reportable “named executive officers” for the last two years include
Kim Bradford, who serves as our Principal Executive Officer, Norman Dowling, who serves as Principal Financial Officer, as well
as Greg Franklin, our Chief Geologist.
During
the last two fiscal years, the following executive officers of our company have received total annual salary and bonus exceeding
$100,000:
| SUMMARY COMPENSATION
TABLE |
| Name and principal position | |
Year | |
Salary | | |
Bonus | | |
Stock Awards | | |
Nonequity incentive
plan compensation | | |
Nonqualified deferred
compensation earnings | | |
All other compensation | | |
Total | |
Kim Bradford
President and CEO | |
2013
2012
| |
$
$ | 300,000 300,000 | | |
$
$ | 0 0 | | |
$
$ | 0 0 | | |
$
$ | 0 0 | | |
$
$ | 0 0 | | |
$
$ | 0 0 | | |
$
$ | 300,000 300,000 | |
Greg Franklin
Chief Geologist | |
2013
2012 | |
$
$ | 240,000 226,154 | | |
$
$ | 0 0 | | |
$
$ | 0 0 | | |
$
$ | 0 0 | | |
$
$ | 0 0 | | |
$
$ | 0 0 | | |
$
$ | 240,000 226,154 | |
On
November 9, 2007, the Company entered into an employment agreement with Kim Bradford to serve as President and Chief Executive
Officer. The agreement was for two years ending November 30, 2009 (“Employment Period”) and allowed Mr. Bradford to
be eligible for an annual bonus as determined by the Board of Directors. In the event Mr. Bradford’s employment is terminated
for a change of control, then he shall be eligible to receive, in one lump payment, the greater of (i) annual base salary in effect
immediately prior to the change of control and (ii) the remaining base salary in effect immediately prior to the change of control
owed to the officer until the end of the Employment Period. Mr. Bradford’s employment agreement included an annual base
salary of $144,000 and a signing bonus of $150,000. Mr. Bradford’s annual base salary was subsequently increased to $240,000
during 2009. In 2011, Mr. Bradford received a cash bonus of $100,000 and an increase in base salary to $300,000 pursuant to a
verbal agreement. The Company is currently negotiating with Mr. Bradford on a new employment contract.
On
November 9, 2007, the Company entered into an employment agreement with Greg Franklin to serve as Chief Geologist. The agreement
was for two years ending November 30, 2009 (“Employment Period”) and allowed Mr. Franklin to be eligible for an annual
bonus as determined by the Board of Directors. In the event that Mr. Franklin’s employment is terminated for a change of
control, then he shall be eligible to receive, in one lump payment, the greater of (i) annual base salary in effect immediately
prior to the change of control and (ii) the remaining base salary in effect immediately prior to the change of control owed to
the officer until the end of the Employment Period. Mr. Franklin’s employment included an annual base salary of $120,000
and a signing bonus of 2,000,000 shares of the Company’s Stock, which vested 100% on January 1, 2009. Mr. Franklin’s
annual base salary was subsequently increased to $240,000 during 2009 pursuant to a verbal agreement. On September 1, 2010, the
Company entered into a new two-year employment agreement with Mr. Franklin to continue serving as Chief Geologist. Mr. Franklin’s
agreement included an annual base salary of $240,000 and the issuance of 1,000,000 shares of the Company’s stock, which
vested immediately upon issuance.
On
January 21, 2013, the Company entered into a consulting agreement with Norman Dowling to serve as Chief Financial Officer in a
part-time capacity. The Company is currently negotiating with Mr. Dowling on a full-time employment contract.
We
do not have any other contractual arrangements with our executive officers, promoters or directors, nor do we have any compensatory
arrangements with our executive officers, promoters or directors other than as described below:
Outstanding
Equity Awards at Fiscal Year-End
| | |
Option Awards | |
Stock Awards |
Name
(a) | |
Number of Securities Underlying Unexercised
Options (#) Exercisable (b) | |
Number of Securities Underlying Unexercised Options
(#) Unexercisable
(c) | |
Equity Incentive Plan Awards Number of Securities
Underlying Unexercised Unearned Options (#) (d) | |
Option Exercise Price
($)
(e) | |
Option Expiration Date (f) | |
Number of Shares or Units of Stock That Have Not
Vested (#)
(g) | |
Market Value of Shares or Units of Stock That
Have Not Vested ($) (h) | |
Equity Incentive Plan Awards: Number of Unearned
Shares, Units or Other Rights That Have Not Vested (#)
(i) | |
Equity Incentive Plan Awards: Market or Payout
Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) (j) |
| Kim Bradford | |
--- | |
--- | |
--- | |
--- | |
--- | |
--- | |
--- | |
--- | |
--- |
| Greg Franklin | |
--- | |
--- | |
--- | |
--- | |
--- | |
--- | |
--- | |
--- | |
--- |
Item
12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The
following table shows information as of March 27, 2014 with respect to each beneficial owner of more than five percent of the
Company’s common stock:
| Name and Address of | |
Common Stock | | |
Percent | |
| Beneficial
Owner | |
Beneficially
Owned | | |
of
Class | |
| Kim Bradford | |
| 7,035,000 | | |
| 12.2 | % |
| 2445 5th Avenue, Suite 310 | |
| | | |
| | |
| San Diego, CA 92101 | |
| | | |
| | |
| Mustang Capital Venture, LLC [1] | |
| 5,250,000 | | |
| 9.1 | % |
| 10101 Reunion Place, Suite 1000 | |
| | | |
| | |
| San Antonio, TX 78216 | |
| | | |
| | |
| Greg L. Franklin | |
| 3,950,000 | | |
| 6.9 | % |
| 324 N. Robinson, 8th Floor | |
| | | |
| | |
| Oklahoma City, OK 73102 | |
| | | |
| | |
The
percentage ownership is based on 57,591,342 shares outstanding at March 27, 2014
[1]
Information is derived from Schedule 13D filed by Mustang Capital Venture, LLC on March 16, 2009.
The
following table shows information as of March 27, 2014 with respect to each of the beneficial owners of the Company’s common
stock by its executive officers, directors and nominee individually and as a group:
| Name and Address of | |
Common Stock | | |
Percent | |
| Beneficial
Owner | |
Beneficially
Owned | | |
of
Class | |
| Kim Bradford | |
| 7,035,000 | | |
| 12.2 | % |
| 2445 5th Avenue, Suite 310 | |
| | | |
| | |
| San Diego, CA 92101 | |
| | | |
| | |
| Greg L. Franklin | |
| 3,950,000 | | |
| 6.9 | % |
| 324 N. Robinson,
8th Floor | |
| | | |
| | |
| Oklahoma City, OK 73102 | |
| | | |
| | |
| Officers and Directors as a | |
| 10,985,000 | | |
| 19.1 | % |
| Group (2 people) | |
| | | |
| | |
The
percentage ownership is based on 57,591,342 shares outstanding at March 27, 2014.
There
are no family relationships among the directors and executive officers.
Changes
in Control
On
December 28, 2006, a change of control occurred when Kim Bradford, our Chief Executive Officer, President, and Chairman, along
with other investors entered into a transaction with the Company whereby for a $470,875 promissory note, the Company issued a
total of 18,835,000 shares of Common stock, or approximately 64% of the total shares outstanding. The shares were valued based
on the approximate asset value per share prior to the transaction. Of the $470,875 promissory notes, Mr. Bradford issued a note
in the amount of $151,375 for the purchase of 6,055,000 shares. In December 2007, Mr. Bradford paid in full his note plus accrued
interest. The notes matured December 31, 2011 and at December 31, 2013, there are notes receivable for $95,000, representing 3,800,000
shares. The Company is currently attempting to collect the notes receivable.
Item
13. Certain Relationships and Related Transactions
There
have been no transactions during the last two years, or proposed transactions, to which we were or are to be a party in which
any of the following persons had or is to have a direct or indirect material interest:
| ● | any
officer or director; |
| | | |
| ● | any
nominee for election as a director; |
| | | |
| ● | any
beneficial owner of more than five percent of our voting securities; |
| | | |
| ● | any
member of the immediate family of any of the above persons. |
Director
Independence
Our
BOD is made up of Kim Bradford, our President and Chief Executive Officer and Greg Franklin, our Chief Geologist. Our common stock
trades on the Over-the-Counter Bulletin Board. Because we are traded on the Over-the-Counter Bulletin Board, we are not currently
subject to corporate governance standards of listed companies, which require, among other things, that the majority of the Board
of Directors be independent.
Since
we are not currently subject to corporate governance standards relating to the independence of our directors, we choose to define
an “independent” director in accordance with applicable independence standards required of issuers listed on the NASDAQ
Capital Market. NASDAQ Marketplace Rule 4200(a)(15) defines an “Independent director” as a person other than an executive
officer or employee of the company or any other individual having a relationship which, in the opinion of the issuer’s BOD,
would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. At this time, the
Board has determined that none of its directors are independent under the above definition.
Item
14. Principal Accounting Fees and Services
Selection
of our Independent Registered Public Accounting Firm is made by the BOD. Mayer Hoffman McCann P.C. (“MHM”) has been
selected as our Independent Registered Public Accounting Firm for the current fiscal year. MHM
leases substantially all its personnel, who work under the control of MHM shareholders, from wholly-owned subsidiaries of CBIZ,
Inc., in an alternative practice structure. All audit and
non-audit services provided by MHM are pre-approved by the BOD which gives due consideration to the potential impact of non-audit
services on auditor independence.
In
accordance with applicable requirements of the Public Company Accounting Oversight Board regarding the independent accountant’s
communications with the audit committee concerning independence, we received a letter and verbal communication from MHM that it
knows of no state of facts which would impair its status as our independent public accountants. There were no non-audit services
provided by our Independent Registered Public Accounting Firms in 2013 or 2012.
AUDIT
FEES
For
2013, we were billed $85,000 by MHM and $32,500 by MaloneBailey, LLP and for 2012, we were billed $65,000 by MaloneBailey, LLP
and $20,000 by Goldman, Kurkland and Mohidin, LLP, for audit services.
TAX
FEES
Our
auditors did not bill us for any tax services during 2013 and 2012.
ALL
OTHER FEES
Our
auditors did not bill us for any other services during 2013 and 2012.
Part
IV
Item
15. Exhibit, Financial Statements Schedules
| Exhibit
No. |
|
Description |
| 2.1 |
|
Plan
of Reorganization and Agreement of Merger, dated June 18, 2007 (1) |
| 3.1 |
|
Articles
of Incorporation of Osage Exploration and Development, Inc. (1) |
| 3.2 |
|
Bylaws
of Osage Exploration and Development, Inc. (1) |
| 10.1 |
|
Agreement
for Acquisition of Oil and Gas Leaseholds between Conquest Exploration Company, LLC, David Farmer, Charles Volk, Jr. and Osage
Energy Company, LLC dated November 10, 2004. (1) |
| 10.2 |
|
Assignment
and Bill of Sale between Conquest Exploration Company, LLC and Osage Energy Company, LLC dated January 24, 2005. (1) |
| 10.3 |
|
$250,000
Note and Security Agreement with Vision Opportunity Master Fund, Ltd. dated February 13, 2007. (1) |
| 10.4 |
|
$1,100,000
Unsecured Convertible Promissory Note with Marie Baier Foundation dated July 16, 2007. (2) |
| 10.5 |
|
Form
of Warrant issued to Marie Baier Foundation in connection with the $1,100,000 Unsecured Convertible Promissory Note. (2) |
| 10.6 |
|
Rosa
Blanca Carried Interest Agreement dated June 21, 2007. (3) |
| 10.7 |
|
2007
Equity Based Compensation Plan (4) |
| 10.8 |
|
Purchase
and Sale Agreement for the purchase of the Hansford Property (4) |
| 10.8.1 |
|
Extension
Agreement with Pearl Resources, Corp. for the Hansford Property (5) |
| 10.8.2 |
|
Letter
from Charles Volk regarding Ownership of the Hansford Property (6) |
| 10.9 |
|
Consulting
Agreement dated January 1, 2007 with Greg Franklin (4) |
| 10.11 |
|
Form
of Stock Subscription Receivable dated December 28, 2006 (4) |
| 10.11.1 |
|
Form
of Amendment #1 to Stock Subscription Receivable dated August 1, 2007 (4) |
| 10.12 |
|
Oil
and Gas Mining Lease with the Osage Nation dated July 21, 1999 (4) |
| 10.13 |
|
Office
lease agreement with Catalyst Consulting Partners, LLC (4) |
| 10.14 |
|
Employment
Agreement with Kim Bradford, President and CEO (7) |
| 10.15 |
|
Employment
Agreement with Greg Franklin, Chief Geologist (7) |
| 10.15.1 |
|
Restricted
Stock Agreement with Greg Franklin, Chief Geologist (7) |
| 10.17 |
|
Office
Lease, dated February 1, 2008, by and between Osage Exploration & Development, Inc. and Fifth & Laurel Associates,
LLC. (8) |
| 10.18 |
|
Membership
Purchase Interest between Osage Exploration and Development, Inc. and Sunstone Corporation dated April 8, 2008 (9) |
| 10.19 |
|
Independent
Contractor Agreement between Osage Exploration and Development, Inc. and E. Peter Hoffman, Jr. dated July 2, 2008 (10) |
| 10.20 |
|
Agreement
between Lewis Energy Colombia, Inc., Gold Oil Plc Sucursal Colombia and Osage Exploration and Development, Inc. and Osage
Exploration and Development, Inc., Sucrusal Colombia dated March 3, 2009 (11) |
| 10.21 |
|
Settlement
Agreement between Lewis Energy Colombia, Inc., Gold Oil Plc Sucursal Colombia, EMPESA, SA, and Osage Exploration and Development,
Inc. Sucrusal Colombia dated September 15, 2009 (12) |
| 10.22 |
|
Employment
Agreement with Greg Franklin, Chief Geologist (13) |
| 10.22.1 |
|
Restricted
Stock Agreement with Greg Franklin, Chief Geologist (13) |
| 10.23 |
|
$500,000
Promissory Note to Blackrock Management, Inc. (14) |
| 10.23.1 |
|
Escrow
Agreement between Osage Exploration and Development, Inc., Blackrock Management, Inc. and Robertson & Williams (14) |
| 10.23.2 |
|
Assignment
of Oil and Gas Leases between Osage Exploration and Development, Inc. and Blackrock Management, Inc. (14) |
| 10.23.3 |
|
Mortgage
between Osage Exploration and Development, Inc. and Blackrock Management, Inc. (14) |
| 10.24 |
|
$10 million Note Purchase Agreement
with Apollo Investment Corp. (18) |
| 10.24.1 |
|
First Amendment to Note Purchase Agreement
(19) |
| 10.24.2 |
|
Second Amendment to Note Purchase Agreement
(20) |
| 10.25 |
|
Membership Interest Purchase Agreement
(21) |
| 10.26 |
|
Intercreditor Agreement with BP Energy
(21) |
| 10.27 |
|
Partition Agreement with Slawson Exploration
Company, Inc. (22) |
| 10.28 |
|
Form of Securities Purchase Agreement
(23) |
| 10.29 |
|
Form of Common Stock Purchase Warrant
(23) |
| 10.30 |
|
Pinnacle
Energy LLC reserve report for the Logan Property as of December 31, 2012 (17) |
| 10.31 |
|
Pinnacle Energy LLC reserve report for
the Logan Property as of December 31, 2013 (24) |
| 10.31.1 |
|
Consent of Pinnacle Energy LLC (24) |
| 10.32 |
|
Participation Agreement with Slawson
Exploration Company and US Energy Development Corporation (*) |
| 21.1 |
|
List
of Subsidiaries (24) |
| 31.1 |
|
Certification
of Chief Executive pursuant to Rule 13a-14 and Rule 15d-14(a), promulgated under the Securities and Exchange Act of 1934,
as amended. (*) |
| 31.2 |
|
Certification
of Chief Financial pursuant to Rule 13a-14 and Rule 15d-14(a), promulgated under the Securities and Exchange Act of 1934,
as amended. (*) |
| 32.1 |
|
Certification
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive
Officer) (*) |
| 32.2 |
|
Certification
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Financial
Officer) (*) |
| 101.INS |
|
XBRL Instance Document ** |
| 101.SCH |
|
XBRL Taxonomy Extension Schema Document
** |
| 101.CAL |
|
XBRL Taxonomy Extension Calculation
Linkbase Document ** |
| 101.DEF |
|
XBRL Taxonomy Extension Definition
Linkbase Document ** |
| 101.LAB |
|
XBRL Taxonomy Extension Label Linkbase
Document ** |
| 101.PRE |
|
XBRL Taxonomy Extension Presentation
Linkbase Document ** |
| (1) |
| Incorporated
by reference to Osage’s Form 10-SB filed July 6, 2007 |
| (2) |
| Incorporated
by reference to Osage’s Form 8-k filed July 17, 2007 |
| (3) |
| Incorporated
by reference to Osage’s Form 8-k filed August 13, 2007 |
| (4) | | Incorporated
by reference to Osage’s Form 10-SB Amendment No. 1 filed August 27, 2007 |
| (5) | | Incorporated
by reference to Osage’s Form 10-SB Amendment No. 2 filed October 15, 2007 |
| (6) | | Incorporated
by reference to Osage’s Form 10-SB Amendment No. 3 filed November 19, 2007 |
| (7) | | Incorporated
by reference to Osage’s Form 10-SB Amendment No. 5 filed December 28, 2007 |
| (8) | | Incorporated
by reference to Osage’s Form 8-k filed March 4, 2008 |
| (9) | | Incorporated
by reference to Osage’s Form 8-k filed April 10, 2008 |
| (10) | | Incorporated
by reference to Osage’s Form 8-k filed July 7, 2008 |
| (11) | | Incorporated
by reference to Osage’s Form 8-k filed March 5, 2009 |
| (12) | | Incorporated
by reference to Osage’s Form 8-k filed September 17, 2009 |
| (13) | | Incorporated
by reference to Osage’s Form 8-k filed September 7, 2011 |
| (14) | | Incorporated
by reference to Osage’s Form 8-k filed January 26, 2011 |
| (15) | | Incorporated
by reference to Osage’s Form 10-K/a filed September 7, 2011 |
| (16) | | Incorporated
by reference to Osage’s Form 10-K filed March 23, 2012 |
| (17) | | Incorporated
by reference to Osage’s Form 10-K filed April 2, 2013 |
| (18) | | Incorporated
by reference to Osage’s Form 8-k filed May 1, 2012 |
| (19) | | Incorporated
by reference to Osage’s Form 8-k filed April 8, 2013 |
| (20) | | Incorporated
by reference to Osage’s Form 10-Q filed August 14, 2013 |
| (21) | | Incorporated
by reference to Osage’s Form 10-Q filed November 11, 2013 |
| (22) | | Incorporated
by reference to Osage’s Form 8-k filed December 23, 2013 |
| (23) | | Incorporated
by reference to Osage’s Form 8-k filed February 25, 2014 |
| (24) | | Incorporated
by reference to Osage’s Form 10-K filed March 31, 2014 |
| (*) | | Filed
with this Form 10-K/A |
| ** |
|
In
accordance with Regulation S-T, the XBRL-formatted interactive data files that comprise Exhibit 101 in this Annual Report
on Form 10-K shall be deemed “furnished” and not “filed”. |
SIGNATURES
In
accordance with the requirements of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
OSAGE
EXPLORATION & DEVELOPMENT, INC.
| BY: |
/s/
KIM BRADFORD |
|
| |
Kim
Bradford |
|
| |
President
and C.E.O. |
|
Dated:
September 24, 2014
| BY: |
/s/
Norman Dowling |
|
| |
Norman
Dowling |
|
| |
Chief
Financial Officer |
|
Dated:
September 24, 2014
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf
of the registrant and in the capacities and on the dates indicated.
| Signature |
|
Title |
|
Date |
| |
|
|
|
|
| /s/
KIM BRADFORD |
|
President,
Chief Executive Officer, and Chairman |
|
September
24, 2014 |
| Kim
Bradford |
|
(Principal
Executive Officer) |
|
|
| |
|
|
|
|
| /s/
GREG FRANKLIN |
|
Chief
Geologist and Director |
|
September
24, 2014 |
| Greg
Franklin |
|
|
|
|
| |
|
|
|
|
| /s/
GREGORY HOLCOMBE |
|
Director |
|
September 24, 2014 |
| Gregory Holcombe |
|
|
|
|
| |
|
|
|
|
| /s/
NORMAN DOWLING |
|
Chief
Financial Officer
|
|
September
24, 2014 |
| Norman
Dowling |
|
(Principal
Financial Officer) |
|
|
OSAGE
EXPLORATION AND DEVELOPMENT, INC.
INDEX
TO FINANCIAL STATEMENTS
Set
forth below are the following consolidated financial statements for the Company for the years ended December 31, 2013 and 2012:
Report
of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
of
Osage Exploration and Development,
Inc.
We have audited the accompanying consolidated
balance sheet of Osage Exploration and Development, Inc. as of December 31, 2013, and the related consolidated statements of operations
and other comprehensive income (loss), stockholders’ equity and cash flows for the year then ended. These financial statements
are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements
based on our audit.
We conducted our audit in accordance with
the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company
is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit
included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate
in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control
over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides
a reasonable basis for our opinion.
In our opinion, the financial statements referred
to above present fairly, in all material respects, the consolidated financial position of Osage Exploration and Development, Inc.
as of December 31, 2013, and the consolidated results of its operations and its cash flows for the year then ended in conformity
with accounting principles generally accepted in the United States of America.
The accompanying financial statements have
been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements,
the Company has incurred recurring losses from operations and, as of December 31, 2013, has current liabilities significantly
in excess of current assets. These conditions, among others as discussed in Note 2 to the financial statements, raise substantial
doubt about its ability to continue as a going concern. Management’s plans regarding these matters are also described in
Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
| /s/
Mayer Hoffman McCann P.C. |
|
| San
Diego, California |
|
| March
31, 2014 |
|
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To
the Board of Directors and Shareholders
Osage
Exploration and Development, Inc. and Subsidiaries
San
Diego, CA
We
have audited the accompanying consolidated balance sheet of Osage Exploration and Development, Inc. and subsidiaries (collectively
“the Company”) as of December 31, 2012, and the related consolidated statements of operations and other comprehensive
income (loss), stockholders’ equity, and cash flows for the year then ended. These financial statements are the responsibility
of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We
conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material
misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial
reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures
that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s
internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe
that our audit provides a reasonable basis for our opinion.
In
our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position
of Osage Exploration and Development, Inc. and subsidiaries as of December 31, 2012 and the results of their operations and their
cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.
The
accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern.
As discussed in Note 2 to the consolidated financial statements, the Company has a working capital deficit and an accumulated
deficit as of December 31, 2012 which raises substantial doubt about its ability to continue as a going concern. Management’s
plans regarding those matters are described in Note 2. The consolidated financial statements do not include any adjustments that
might result from the outcome of this uncertainty.
www.malonebailey.com
Houston,
Texas
April
2, 2013, except for the effects of discontinued operations, for which the date is March 31, 2014
OSAGE
EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS
As
of December 31, 2013 and December 31, 2012
| | |
2013 | | |
2012 | |
| ASSETS | |
| | | |
| | |
| | |
| | | |
| | |
| Current assets: | |
| | | |
| | |
| Cash
and equivalents | |
$ | 2,782,643 | | |
$ | 486,205 | |
| Accounts
receivable | |
| 2,769,414 | | |
| 371,544 | |
| Short
term assets held for sale | |
| - | | |
| 114,568 | |
| Prepaid
expenses and other current assets | |
| 596,742 | | |
| 83,090 | |
| Deferred
financing costs | |
| 1,829,124 | | |
| 2,924,472 | |
| Total current
assets | |
| 7,977,923 | | |
| 3,979,879 | |
| | |
| | | |
| | |
| Property and
equipment, at cost: | |
| | | |
| | |
| Oil
& gas properties and equipment (successful efforts method) | |
| 27,339,460 | | |
| 9,503,172 | |
| Other
property & equipment | |
| 85,746 | | |
| 85,746 | |
| |
| 27,425,206 | | |
| 9,588,918 | |
| Less:
accumulated depletion, depreciation and amortization | |
| (2,683,085 | ) | |
| (289,490 | ) |
| | |
| 24,742,121 | | |
| 9,299,428 | |
| | |
| | | |
| | |
| Restricted
cash | |
| 908,645 | | |
| 157,467 | |
| Long term
assets held for sale | |
| - | | |
| 1,289,273 | |
| Note
receivable | |
| - | | |
| 6,000 | |
| Total
assets | |
$ | 33,628,689 | | |
$ | 14,732,047 | |
| | |
| | | |
| | |
| LIABILITIES
AND STOCKHOLDERS’ EQUITY | |
| | | |
| | |
| | |
| | | |
| | |
| Current liabilities: | |
| | | |
| | |
| Accounts
payable | |
$ | 555,784 | | |
$ | 218,190 | |
| Income
taxes payable | |
| 56,469 | | |
| 58,093 | |
| Accrued
expenses | |
| 61,331 | | |
| 22,152 | |
| Unrealized
losses on oil and gas derivatives | |
| 265,961 | | |
| - | |
| Short
term liabilities held for sale | |
| - | | |
| 1,325,287 | |
| Notes
payable, current portion | |
| 20,000,000 | | |
| 3,000,000 | |
| Total
current liabilities | |
| 20,939,545 | | |
| 4,623,722 | |
| | |
| | | |
| | |
| Notes payable,
net of current portion and net of $271,060 debt discount as of December 31, 2012 | |
| - | | |
| 2,228,940 | |
| Unrealized
losses on oil and gas derivatives, net of current portion | |
| 91,606 | | |
| - | |
| Liability
for asset retirement obligations | |
| 3,886 | | |
| 19 | |
| Total
liabilities | |
| 21,035,037 | | |
| 6,852,681 | |
| | |
| | | |
| | |
| Commitments
and contingencies | |
| | | |
| | |
| | |
| | | |
| | |
| Stockholders’
Equity: | |
| | | |
| | |
| Preferred stock,
$0.0001 par value, 10,000,000 shares authorized, none issued and outstanding as of December 31, 2013 or December 31, 2012 | |
| - | | |
| - | |
| Common
stock, $0.0001 par value, 190,000,000 shares authorized; 49,854,675 and 49,094,675 shares issued and outstanding as of December
31, 2013 and December 31, 2012, respectively | |
| 4,985 | | |
| 4,909 | |
| Additional
paid-in capital | |
| 16,903,147 | | |
| 16,371,305 | |
| Stock
purchase notes receivable | |
| (95,000 | ) | |
| (95,000 | ) |
| Accumulated
deficit | |
| (4,219,480 | ) | |
| (8,074,786 | ) |
| Accumulated
other comprehensive loss - currency translation loss | |
| - | | |
| (327,062 | ) |
| Total
stockholders’ equity | |
| 12,593,652 | | |
| 7,879,366 | |
| Total
liabilities and stockholders’ equity | |
$ | 33,628,689 | | |
$ | 14,732,047 | |
The
accompanying notes are an integral part of these consolidated financial statements.
OSAGE
EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF OPERATIONS AND OTHER COMPREHENSIVE INCOME (LOSS)
For
Years Ended December 31, 2013 and 2012
| | |
Years
Ended December 31, | |
| | |
2013 | | |
2012 | |
| Operating
revenues | |
| | | |
| | |
| Oil
revenues | |
$ | 7,339,943 | | |
$ | 2,030,596 | |
| Natural
gas revenues | |
| 689,145 | | |
| 233,417 | |
| Total
operating revenues | |
| 8,029,088 | | |
| 2,264,013 | |
| | |
| | | |
| | |
| Operating
costs and expenses | |
| | | |
| | |
| Operating
costs | |
| 1,547,949 | | |
| 258,686 | |
| General
and administrative expenses | |
| 2,613,920 | | |
| 2,661,922 | |
| Depreciation,
depletion and accretion | |
| 2,320,441 | | |
| 314,540 | |
| Loss
on disposal of fixed assets | |
| - | | |
| 21,599 | |
| | |
| | | |
| | |
| Total
operating costs and expenses | |
| 6,482,310 | | |
| 3,256,747 | |
| | |
| | | |
| | |
| Operating
income (loss) | |
| 1,546,778 | | |
| (992,734 | ) |
| | |
| | | |
| | |
| Other income
(expenses): | |
| | | |
| | |
| Interest
income | |
| 2,000 | | |
| 2,878 | |
| Interest
expense | |
| (4,566,246 | ) | |
| (1,390,277 | ) |
| Loss
on oil and gas derivatives | |
| (495,803 | ) | |
| - | |
| Loss from
continuing operations before income taxes | |
| (3,513,271 | ) | |
| (2,380,133 | ) |
| Provision
for income taxes | |
| 1,624 | | |
| - | |
| Loss
from continuing operations | |
| (3,514,895 | ) | |
| (2,380,133 | ) |
| | |
| | | |
| | |
| Discontinued
operations: | |
| | | |
| | |
| Income
from discontinued operations net of income taxes | |
| 2,496,541 | | |
| 1,863,427 | |
| Gain
on sale of discontinued operations | |
| 4,873,660 | | |
| - | |
| Net
income (loss) | |
| 3,855,306 | | |
| (516,706 | ) |
| | |
| | | |
| | |
| Other comprehensive
income (loss), net of tax: | |
| | | |
| | |
| Foreign
currency translation adjustment attributable to discontinued operations | |
| 24,153 | | |
| (21,460 | ) |
| | |
| | | |
| | |
| Comprehensive
income (loss) | |
$ | 3,879,459 | | |
$ | (538,166 | ) |
| | |
| | | |
| | |
| Basic and
diluted income (loss) per share | |
| | | |
| | |
| Continuing
operations | |
$ | (0.07 | ) | |
$ | (0.05 | ) |
| Discontinued
operations | |
$ | 0.15 | | |
$ | 0.04 | |
| |
| | | |
| | |
| Weighted
average number of common share and common share equivalents used to compute basic and diluted income (loss) per share | |
| 49,762,499 | | |
| 48,385,866 | |
The
accompanying notes are an integral part of these consolidated financial statements.
OSAGE
EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS’ EQUITY
For
Years Ended December 31, 2013 and December 31, 2012
| | |
| | |
| | |
Stock | | |
| | |
Accumulated | | |
| |
| | |
| | |
Additional | | |
Purchase | | |
| | |
Other | | |
| |
| | |
Common
Stock | | |
Paid-In | | |
Note | | |
Accumulated | | |
Comprehensive | | |
Total | |
| | |
Shares | | |
Amount | | |
Capital | | |
Receivable | | |
Deficit | | |
Income
/ (Loss) | | |
Equity | |
| Balance
at December 31, 2011 | |
| 47,884,775 | | |
$ | 4,788 | | |
$ | 12,107,920 | | |
$ | (95,000 | ) | |
$ | (7,558,080 | ) | |
$ | (305,602 | ) | |
$ | 4,154,026 | |
| Issuance of
shares for professional services | |
| 610,000 | | |
| 61 | | |
| 438,922 | | |
| - | | |
| - | | |
| - | | |
| 438,983 | |
| Issuance of
warrants for professional services | |
| - | | |
| - | | |
| 448,111 | | |
| - | | |
| - | | |
| - | | |
| 448,111 | |
| Issuance of
shares for debt discount | |
| 400,000 | | |
| 40 | | |
| 385,616 | | |
| - | | |
| - | | |
| - | | |
| 385,656 | |
| Issuance of
warrants as deferred financing costs | |
| - | | |
| - | | |
| 2,988,756 | | |
| - | | |
| - | | |
| - | | |
| 2,988,756 | |
| Exercise of
warrants | |
| 200,000 | | |
| 20 | | |
| 1,980 | | |
| - | | |
| - | | |
| - | | |
| 2,000 | |
| Cancellation
of shares | |
| (100 | ) | |
| - | | |
| - | | |
| - | | |
| - | | |
| - | | |
| - | |
| Net loss | |
| - | | |
| - | | |
| - | | |
| - | | |
| (516,706 | ) | |
| - | | |
| (516,706 | ) |
| Foreign
exchange translation adjustment | |
| - | | |
| - | | |
| - | | |
| - | | |
| - | | |
| (21,460 | ) | |
| (21,460 | ) |
| Balance at
December 31, 2012 | |
| 49,094,675 | | |
| 4,909 | | |
| 16,371,305 | | |
| (95,000 | ) | |
| (8,074,786 | ) | |
| (327,062 | ) | |
| 7,879,366 | |
| Issuance of
shares for professional services | |
| 410,000 | | |
| 41 | | |
| 375,959 | | |
| - | | |
| - | | |
| - | | |
| 376,000 | |
| Stock based
compensation | |
| - | | |
| - | | |
| 152,418 | | |
| - | | |
| - | | |
| - | | |
| 152,418 | |
| Exercise of
warrants | |
| 350,000 | | |
| 35 | | |
| 3,465 | | |
| - | | |
| - | | |
| - | | |
| 3,500 | |
| Net income | |
| - | | |
| - | | |
| - | | |
| - | | |
| 3,855,306 | | |
| - | | |
| 3,855,306 | |
| Foreign exchange
translation adjustment | |
| - | | |
| - | | |
| - | | |
| - | | |
| - | | |
| 24,153 | | |
| 24,153 | |
| Recognition
of accumulated currency translation loss | |
| - | | |
| - | | |
| - | | |
| - | | |
| - | | |
| 302,909 | | |
| 302,909 | |
| Balance
at December 31, 2013 | |
| 49,854,675 | | |
$ | 4,985 | | |
$ | 16,903,147 | | |
$ | (95,000 | ) | |
$ | (4,219,480 | ) | |
$ | - | | |
$ | 12,593,652 | |
The
accompanying notes are an integral part of these consolidated financial statements.
OSAGE
EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
For
Years Ended December 31, 2013 and 2012
| | |
2013 | | |
2012 | |
| Cash flows
from operating activities: | |
| | | |
| | |
| Net
income (loss) | |
$ | 3,855,306 | | |
$ | (516,706 | ) |
| Adjustments
to reconcile net income (loss) to net cash provided by operating activities: | |
| | | |
| | |
| Shares
issued for services | |
| 528,418 | | |
| 448,583 | |
| Warrants
issued for services | |
| - | | |
| 448,111 | |
| Amortization
of deferred financing costs | |
| 1,295,348 | | |
| 734,976 | |
| Amortization
of debt discount | |
| 271,060 | | |
| 114,596 | |
| (Gain)
loss on sale of oil & gas properties | |
| (4,873,660 | ) | |
| 21,599 | |
| Write
off of expired mineral rights leases | |
| 44,717 | | |
| - | |
| Accretion
of asset retirement obligation | |
| 228 | | |
| - | |
| Provision
for depletion, depreciation and amortization | |
| 2,320,213 | | |
| 568,777 | |
| Unrealized
loss on oil and gas derivatives | |
| 357,567 | | |
| - | |
| Changes
in operating assets and liabilities: | |
| | | |
| | |
| (Increase)
in accounts receivable | |
| (2,660,855 | ) | |
| (363,548 | ) |
| (Increase)
in prepaid expenses and other current assets | |
| (121,689 | ) | |
| (34,732 | ) |
| (Decrease)
in income tax payable | |
| (1,624 | ) | |
| (800 | ) |
| Increase
(decrease) in accounts payable | |
| 332,782 | | |
| (86,722 | ) |
| (Decrease)
in asset retirement obligations | |
| - | | |
| (59,950 | ) |
| (Decrease)
increase in accrued expenses | |
| (1,267,320 | ) | |
| 687,887 | |
| Net
cash provided by operating activities | |
| 80,491 | | |
| 1,962,071 | |
| | |
| | | |
| | |
| Cash flows
from investing activities: | |
| | | |
| | |
| Investments
in oil & gas properties | |
| (17,891,932 | ) | |
| (12,781,375 | ) |
| Investments
in non-oil & gas properties | |
| - | | |
| (5,804 | ) |
| Net
proceeds from assignment of leases | |
| 14,568 | | |
| 4,686,610 | |
| (Increase)
in restricted cash | |
| (751,178 | ) | |
| (127,467 | ) |
| Net
proceeds from sale of oil & gas properties | |
| 6,295,193 | | |
| 125,000 | |
| Cash
included in sale of oil & gas properties | |
| (38,039 | ) | |
| - | |
| Proceeds
from notes receivable | |
| 6,000 | | |
| 5,000 | |
| Net
cash (used) by investing activities | |
| (12,365,388 | ) | |
| (8,098,036 | ) |
| | |
| | | |
| | |
| Cash flows
from financing activities: | |
| | | |
| | |
| Proceeds
from notes payable | |
| 17,000,000 | | |
| 5,500,000 | |
| Proceeds
from term loan | |
| 367,520 | | |
| - | |
| Principal
payments on notes payable | |
| (2,500,000 | ) | |
| - | |
| Principal
payments on term loan | |
| (118,205 | ) | |
| - | |
| Payment
of deferred financing costs | |
| (200,000 | ) | |
| (670,692 | ) |
| Proceeds
from exercise of warrants | |
| 3,500 | | |
| 2,000 | |
| Net
cash provided by financing activities | |
| 14,552,815 | | |
| 4,831,308 | |
| | |
| | | |
| | |
| Effect of
exchange rate on cash and equivalents | |
| 28,520 | | |
| (113,161 | ) |
| | |
| | | |
| | |
| Net increase
(decrease) in cash and equivalents | |
| 2,296,438 | | |
| (1,417,818 | ) |
| | |
| | | |
| | |
| Cash and equivalents
- beginning of period | |
| 486,205 | | |
| 1,904,023 | |
| | |
| | | |
| | |
| Cash and equivalents
- end of period | |
$ | 2,782,643 | | |
$ | 486,205 | |
| | |
| | | |
| | |
| SUPPLEMENTAL
CASH FLOW INFORMATION: | |
| | | |
| | |
| Cash
payment for interest | |
$ | 2,999,838 | | |
$ | 538,889 | |
| Cash
payment for income taxes | |
$ | 1,624 | | |
| 800 | |
| | |
| | | |
| | |
| SUPPLEMENTAL
DISCLOSURE OF NON-CASH ACTIVITIES: | |
| | | |
| | |
| Warrants
issued as deferred financing fees in connection with Note Purchase Agreement | |
$ | - | | |
$ | 2,988,756 | |
| Shares
issued as debt discount in connection with Secured Promissory Note | |
$ | - | | |
$ | 385,656 | |
| Increase
in asset retirement obligation | |
$ | 3,639 | | |
$ | 19 | |
The
accompanying notes are an integral part of these consolidated financial statements.
OSAGE
EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
December
31, 2013 and 2012
1.
ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE
OF OPERATIONS
Osage
Exploration and Development, Inc. (“Osage” or the “Company”) is an independent energy company engaged
primarily in the acquisition, development, production and sale of oil, natural gas and natural gas liquids. The Company’s
production activities are located in the State of Oklahoma. The principal executive offices of the Company are at 2445 Fifth Avenue,
Suite 310, San Diego, CA 92101.
BASIS
OF CONSOLIDATION
The
consolidated financial statements include the accounts of Osage and its wholly owned subsidiaries, Osage Energy Company, LLC and
Osage Exploration and Development Operating, LLC. Accordingly, all references herein to Osage or the Company include the consolidated
results. All significant inter-company accounts and transactions were eliminated in consolidation. The results, assets and liabilities
of the Company’s former wholly owned subsidiary, Cimarrona, LLC, have been presented as discontinued operations in the consolidated
financial statements.
RECLASSIFICATIONS
Certain
amounts included in the prior year financial statements have been reclassified to conform to the current year’s presentation.
These reclassifications have no affect on the reported results in 2013 or 2012.
RISK
FACTORS RELATED TO CONCENTRATION OF SALES AND PRODUCTS
The
Company’s future financial condition and results of operations depend upon prices received for its oil and natural gas and
the costs of finding, acquiring, developing and producing reserves. Prices for oil and natural gas are subject to fluctuations
in response to changes in supply, market uncertainty and a variety of other factors beyond the Company’s control. These
factors include worldwide political instability (especially in the Middle East), the foreign supply of oil and natural gas, the
price of foreign imports, the level of consumer product demand and the price and availability of alternative fuels.
USE
OF ESTIMATES
The
preparation of financial statements in conformity with accounting principles generally accepted in the United States of America
(“US GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities
and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ from those estimates. Management used significant estimates
in determining the carrying value of its oil and gas producing assets and the associated depreciation and depletion expense related
to sales’ volumes. The significant estimates included the use of proved oil and gas reserve volumes and the related present
value of estimated future net revenues there-from (See Note 15: Supplemental Information About Oil and Gas Producing Activities).
CASH
AND EQUIVALENTS
Cash
and equivalents consist of short-term, highly liquid investments readily convertible into cash with an original maturity of three
months or less.
DEFERRED
FINANCING COSTS
The
Company incurred deferred financing costs in connection with the Note Purchase Agreement (see Note 6), which represented the fair
value of warrants, placement fees and legal fees. Deferred financing costs of $3,859,448 are being amortized over the term of
the Note Purchase Agreement on a straight-line basis.
During
the years ended December 31, 2013 and 2012, respectively, the Company made payments of $200,000 and $670,692 for deferred financing
fees in connection with the Note Purchase Agreement.
Deferred
financing costs at December 31, 2013 and 2012 were $1,829,124 and $2,924,472, respectively. Amortization of deferred financing
costs was $1,295,348 for the year ended December 31, 2013 and $734,976 for the year ended December 31, 2012.
FAIR
VALUE OF FINANCIAL INSTRUMENTS
As
of December 31, 2013 and December 31, 2012, the fair value of cash, accounts receivable, short term debt and accounts payable
approximate carrying values because of the short-term maturity of these instruments.
Financial
Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 820, “Fair Value
Measurements and Disclosures,” requires disclosure of the fair value of financial instruments held by the Company. ASC Topic
825, “Financial Instruments,” defines fair value, and establishes a three-level valuation hierarchy for disclosures
of fair value measurement that enhances disclosure requirements for fair value measures. The carrying amounts reported in the
consolidated balance sheets for receivables and current liabilities each qualify as financial instruments and are a reasonable
estimate of their fair value because of the short period of time between the origination of such instruments and their expected
realization and their current market rate of interest.
The
three levels of valuation hierarchy are defined as follows:
| |
● |
|
Level
1 inputs to the valuation methodology are quoted prices for identical assets or liabilities in active markets. |
| |
|
|
|
| |
● |
|
Level
2 inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, quoted prices
for identical or similar assets in inactive markets, and inputs that are observable for the asset or liability, either directly
or indirectly, for substantially the full term of the financial instrument. |
| |
|
|
|
| |
● |
|
Level
3 inputs to the valuation methodology us one or more unobservable inputs which are significant to the fair value measurement. |
The
Company analyzes all financial instruments with features of both liabilities and equity under ASC Topic 480, “Distinguishing
Liabilities from Equity,” and ASC Topic 815, “Derivatives and Hedging.”
As
of December 31, 2013 the Company identified certain derivative financial instruments which required disclosure at fair value on
the balance sheet.
The
following table presents information for those assets and liabilities requiring disclosure at fair value as of December 31, 2013:
| | |
| | |
Total | | |
Fair
Value Measurements Using | |
| | |
Carrying | | |
Fair | | |
Level
1 | | |
Level
2 | | |
Level
3 | |
| | |
Amount | | |
Value | | |
Inputs | | |
Inputs | | |
Inputs | |
| December
31, 2013 assets (liabilities): | |
| | | |
| | | |
| | | |
| | | |
| | |
| Commodity
derivative liability | |
| (357,567 | ) | |
| (357,567 | ) | |
| - | | |
| (357,567 | ) | |
| - | |
The
following methods and assumptions were used to estimate the fair values in the tables above.
Level
2 Fair Value Measurements
Commodity
derivatives — The fair values of commodity derivatives are estimated using internal option
pricing models based upon forward curves and data obtained
from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.
CONCENTRATION
OF CREDIT RISK
Financial
instruments that potentially subject the Company to concentrations of credit risk are cash and accounts receivable arising from
its normal business activities. The Company places its cash in what it believes are credit-worthy financial institutions. However,
the Company’s cash balances have exceeded the FDIC insured levels at various times during 2013 and 2012. The Company maintains
cash accounts only at large, high quality financial institutions and believes the credit risk associated with cash held in banks
exceeding the FDIC insured levels is remote. The Company generated substantially all of its revenues from four customers in 2013
and three customers in 2012. (See “Accounts Receivable and Allowance for Doubtful Accounts” below).
RESTRICTED
CASH
In
connection with the Apollo Note Purchase Agreement, as amended (see Note 6), the Company has classified $850,000, representing
three months interest, as restricted cash as of December 31, 2013. In connection with the Boothbay Secured Promissory Note (see
Note 6) the Company was required to deposit certain royalty interests of Boothbay’s into joint accounts held by the Company
for the benefit of Boothbay. The royalty interests at December 31, 2012 were $102,467 and there were no royalty interests at December
31, 2013 as the Secured Promissory Note had been repaid in full. The Company has also pledged $58,645 for certain bonds and sureties.
Restricted cash at December 31, 2013 was $908,645, compared to $157,467 at December 31, 2012.
ACCOUNTS
RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS
The
Company recognizes accounts receivable when sales are invoiced and regularly reviews accounts receivable for doubtful accounts.
During
the year ended December 31, 2013, the Company sold 80% of its oil and gas production to one customer, Slawson Exploration Company
(“Slawson”). However, the Company believes it can sell all its production to many different purchasers, most of whom
pay similar prices that vary with the international spot market prices. The Company controls credit risk related to accounts receivable
through credit approvals, credit limits and monitoring procedures. The Company routinely assesses the financial strength of its
customers and, based upon factors surrounding the credit risk, establishes an allowance, if required, for uncollectible accounts
and, as a consequence, believes that its accounts receivable credit risk exposure beyond such allowance is limited. The Company
had no allowance as of December 31, 2013 and 2012. The analysis was based on its evaluation of specific customers’ balances
and the collectability thereof.
OIL
AND GAS PROPERTIES
Osage
is an exploration and production oil and natural gas company with proved reserves and existing production in the state of Oklahoma.
The
costs of drilling and equipping exploratory wells are capitalized until they are determined to be either successful or unsuccessful.
If the wells are successful, the costs of the wells remain capitalized. If, however, the wells are unsuccessful, the capitalized
costs of drilling the wells, net of any salvage value, are charged to operations in the period the wells are determined to be
unsuccessful. The costs of drilling and equipping development wells are capitalized, whether the wells are successful or unsuccessful.
The
provision for depreciation and depletion of oil and gas properties is computed by the unit-of-production method. Under this method,
the Company computes the provision by multiplying the total costs of oil and gas properties including future development, site
restoration, and dismantlement abandonment costs, but excluding costs of unproved properties by an overall rate determined by
dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves.
This calculation is done on a field-by-field basis. As of December 31, 2013
and 2012, the Company’s oil production from continuing operations are conducted
in the United States of America. The cost of undeveloped properties not being amortized,
to the extent there is such a cost, is assessed quarterly based on the estimated economic chance
of success and the length of time that the Company expects to hold the properties
to determine whether the value has been impaired below the capitalized cost. The costs associated with unevaluated properties
relate to projects which were undergoing exploration or development activities or in which the Company intends to commence such
activities in the future. The Company will begin to amortize these costs when proved reserves are established or impairment is
determined. Management believes no such impairment exists at December 31, 2013 and 2012.
The
Company follows the “successful efforts” method of accounting for its oil and gas exploration and development activities,
as set forth in FASB ASC topic 932. Under this method, the Company initially capitalizes expenditures for oil and gas property
acquisitions until they are either determined to be successful (capable of commercial production) or unsuccessful. The carrying
value of all undeveloped oil and gas properties is evaluated periodically and reduced if such carrying value appears to have been
impaired. Leasehold costs relating to successful oil and gas properties remain capitalized while leasehold costs which have been
proved unsuccessful are charged to operations in the period the leasehold costs are proved unsuccessful. Costs of carrying and
retaining unproved properties are expensed as incurred.
ASSET
RETIREMENT OBLIGATIONS
In
accordance with FASB ASC topic 410, the Company reports a liability for any legal retirement obligations on its oil and gas properties.
The asset retirement obligations represent the estimated present value of the amounts expected to be incurred to plug, abandon,
and remediate the producing properties at the end of their productive lives, in accordance with state laws, as well as the estimated
costs associated with the reclamation of the property surrounding. The Company determines the asset retirement obligations by
calculating the present value of estimated cash flows related to the liability. The asset retirement obligations are recorded
as a liability at the estimated present value as of the asset’s inception, with an offsetting increase to producing properties.
Periodic accretion of the discount related to the estimated liability is recorded as interest expense in the statement of operations.
The
estimated liability is determined using significant assumptions, including current estimates of plugging and abandonment costs,
annual inflation of these costs, the productive lives of wells, and a risk-adjusted interest rate. Changes in any of these assumptions
can result in significant revisions to the estimated asset retirement obligations. Revisions to the asset retirement obligations
are recorded with an offsetting change to producing properties, resulting in prospective changes to depletion and depreciation
expense and accretion of the discount. Because of the subjectivity of assumptions and the relatively long lives of most of the
wells, the costs to ultimately retire the Company’s wells may vary significantly from prior estimates.
OTHER
PROPERTY AND EQUIPMENT
Non-oil
and gas producing properties and equipment are stated at cost; major renewals and improvements are charged to the property and
equipment accounts; while replacements, maintenance and repairs, which do not improve or extend the lives of the respective assets,
are expensed as incurred. At the time property and equipment are retired or otherwise disposed of, the asset and related accumulated
depreciation accounts are relieved of the applicable amounts. Gains or losses from retirements or sales are credited or charged
to operations.
Depreciation
for non-oil and gas properties is recorded on the straight-line method at rates based on estimated useful lives ranging from three
to fifteen years of the assets.
IMPAIRMENT
OF LONG-LIVED ASSETS
The
Company follows the guidance provided under FASB ASC Topic 360 (“ASC 360”), “Accounting for the Impairment or
Disposal of Long-Lived Assets”, which addresses financial accounting and reporting for the impairment or disposal of long-lived
assets. The Company periodically evaluates the carrying value of long-lived assets to be held and used in accordance with ASC
360. ASC 360 requires impairment losses to be recorded on long-lived assets used in operations when indicators of impairment are
present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amounts.
In that event, a loss is recognized based on the amount by which the carrying amount exceeds the fair market value of the long-lived
assets. Loss on long-lived assets to be disposed of is determined in a similar manner, except that fair market values are reduced
for the cost of disposal. During the years ended December 31, 2013 and 2012, the Company did not record impairment charges related
to its long-lived assets.
REVENUE
RECOGNITION
Revenues
from the sale of crude oil, natural gas and natural gas liquids are recognized when the product is delivered at a fixed or determinable
price, title has transferred, collectability is reasonably assured and evidenced by a contract. The Company follows the sales
method of accounting for its oil and natural gas revenue, so it recognizes revenue on all crude oil, natural gas and natural gas
liquids sold to purchasers, regardless of whether the sales are proportionate to its ownership in the property. A receivable or
liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected
remaining proved reserves. The Company has no imbalance positions at December 31, 2013 or 2012, and no receivables, payables or
unearned revenue are recorded.
STOCK
BASED COMPENSATION
The
Company accounts for its stock-based compensation in accordance with FASC ASC topic 718. The Company recognizes in the statement
of operations the grant-date fair value of stock options and other equity-based compensation issued to employees and non-employees.
For stock-based awards the value is based on the market value for the stock on the date of grant and if the stock has restrictions
as to transferability a discount is provided for lack of tradability. Stock option awards are valued using the Black-Scholes option-pricing
model. For shares issued for services or property, the value is based on the market value for the stock on the date of grant.
INCOME
TAXES
The
Company follows FASB ASC Topic 740 (“ASC 740”), “Accounting for Uncertainty in Income Taxes.” When tax
returns are filed, it is likely some positions taken would be sustained upon examination by the taxing authorities, while others
are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained.
The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence,
management believes it is more likely than not the position will be sustained upon examination, including the resolution of appeals
or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet
the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely
of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions
taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying
balance sheets along with any associated interest and penalties that would be payable to the taxing authorities upon examination.
Interest associated with unrecognized tax benefits are classified as interest expense and penalties are classified in selling,
general and administrative expenses in the Consolidated Statement of Operations. Due to a history of operating losses, the Company
records a full valuation allowance against its net deferred tax assets.
RISK
MANAGEMENT ACTIVITIES
The
Company has entered into certain derivative financial instruments to manage the inherent uncertainty of future revenues. The Company
does not intend to hold or issue derivative financial instruments for speculative purposes and has elected not to designate any
of its derivative instruments for hedge accounting treatment. These derivative financial instruments are marked to market at each
reporting period.
EARNINGS
(LOSS) PER SHARE
In
accordance with FASB ASC Topic 260 “Earnings Per Share,” the Company’s basic net income/loss per share of common
stock is calculated by dividing net income/loss by the weighted-average number of shares of common stock outstanding for the period.
The diluted net income/loss per share of common stock is computed by dividing the net income/loss using the weighted-average number
of common shares including potential dilutive common shares outstanding during the period. Potential common shares are excluded
from the computation of diluted net loss per share if anti-dilutive.
The
following table shows the computation of basic and diluted net income (loss) per share for the years ended December 31, 2013 and
2012:
| | |
Year
Ended December 31, | |
| | |
2013 | | |
2012 | |
| | |
| | |
| |
| Net
loss allocable to continuing operations | |
$ | (3,514,895 | ) | |
$ | (2,380,133 | ) |
| Net
income and gain allocable to discontinued operations | |
$ | 7,370,201 | | |
$ | 1,863,427 | |
| | |
| | | |
| | |
| Basic and
diluted net income (loss) per share | |
| | | |
| | |
| Continuing
operations | |
$ | (0.07 | ) | |
$ | (0.05 | ) |
| Discontinued
operations | |
$ | 0.15 | | |
$ | 0.04 | |
| Basic and
diluted weighted average shares outstanding | |
| 49,762,499 | | |
| 48,385,866 | |
Warrants
to purchase 1,696,843 and 3,071,843 shares of common stock at December 31, 2013 and December 31, 2012, respectively, were excluded
from the computation as their effect would have been anti-dilutive.
RECENTLY
ISSUED ACCOUNTING PRONOUNCEMENTS
The
Company does not expect the adoption of any recently issued accounting pronouncements to have a material effect on the consolidated
financial statements.
2.
GOING CONCERN
The
Company has an accumulated deficit of $4,219,480 and a working capital deficit of $12,961,622 as of December 31, 2013. As of December
31, 2013, as a result of production delays outside of the Company’s control, the Company was not in compliance with certain
covenants including the minimum production covenant under the senior secured note purchase agreement. (see Note 6 - Debt). These
factors raise substantial doubt about the Company’s ability to continue as a going concern.
On
April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement with Apollo Investment Corporation and on
April 5, 2013 we amended this agreement, increasing the facility to $20,000,000.
In
early 2014, the Company raised approximately $6.5 million of gross proceeds in a private placement. (See Note 14 - Subsequent
Events)
Management
of the Company has undertaken steps as part of a plan to improve operations with the goal of sustaining our operations for the
next 12 months and beyond. These steps include (a) becoming operators of our own wells, (b) participating in drilling of wells
in Logan County, Oklahoma within the next 12 months, (c) controlling overhead and expenses, and (d) raising additional equity
and/or debt.
The
Company’s operating plans require additional funds which may take the form of debt or equity financings. The Company’s
ability to continue as a going concern is dependent upon achieving profitable operations and obtaining additional financing. There
is no assurance additional funds will be available on acceptable terms or at all.
These
consolidated financial statements do not give effect to any adjustments which would be necessary should the Company be unable
to continue as a going concern and therefore be required to realize its assets and discharge its liabilities in other than the
normal course of business and at amounts different from those reflected in the accompanying consolidated financial statements.
3.
EQUITY TRANSACTIONS
Common
Stock
On
June 7, 2013, we issued a total of 10,000 shares which vest immediately to two consultants for services rendered with a fair value
of $12,000, or $1.20 per share.
On
January 2, 2013 we issued 400,000 shares which vested immediately to two employees with a fair value of $364,000, or $0.91 per
share.
On
January 27, 2012, the Company issued 90,000 shares of common stock at $41,400 or $0.46 per share, to a consultant as compensation
for services rendered March through August 2012.
On
April 16, 2012, the Company issued 20,000 shares of common stock at $23,000 or $1.15 per share, to a consultant as compensation
for services rendered.
On
April 17, 2012, in connection with the Secured Promissory Note, we issued to Boothbay 400,000 shares of common stock at $385,656,
the relative fair value (see Note 6 – Debt).
On
August 1, 2012, in connection with a three-year employment agreement, we agreed to issue 150,000 shares of common stock at future
dates as specified in the agreement. The agreement specified that we would issue 50,000 shares on each of the first, second, and
third anniversaries of the execution of the agreement subject to other terms and conditions of the agreement. The 150,000 shares
were valued at $177,000, or $1.18 per share, and will be expensed over the three years of the employment agreement. We recognized
$24,582 of expenses as of December 31, 2012. Pursuant to an amendment to this agreement, the 150,000 shares were issued and immediately
vested in early January 2012, and accordingly we recognized the remaining stock-based compensation expense of $152,418 in the
year ended December 31, 2013.
On
November 27, 2012, the Company issued 500,000 shares of common stock at $350,000 or $0.70 per share, to a consultant as compensation
for services rendered.
Warrants
On
April 16, 2012, we issued a warrant to purchase 200,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes
value of $229,056 and a term of 2 years, to a consultant as compensation for services rendered. Variables used in the valuation
include (1) discount rate of 0.27%, (2) expected life of 2 years, (3) expected volatility of 244.0% and (4) zero expected dividends.
On August 24, 2012, the consultant exercised the warrant and purchased the 200,000 shares of common stock for $2,000.
On
April 20, 2012, we issued a warrant to purchase 200,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes
value of $219,055 and a term of 2 years, to a consultant as compensation for services rendered. Variables used in the valuation
include (1) discount rate of 0.29%, (2) expected life of 2 years, (3) expected volatility of 243.0% and (4) zero expected dividends.
On
April 27, 2012, in connection with the Note Purchase Agreement, we issued a warrant to the investor to purchase 1,496,843 shares
of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $2,483,952 and a term of 5 years. Variables used
in the valuation include (1) discount rate of 0.82%, (2) expected life of 5 years, (3) expected volatility of 245.0% and (4) zero
expected dividends. At closing of the Note Purchase Agreement, we issued a warrant to the placement agent to purchase 250,000
shares of common stock, $0.0001 par value, exercisable at $0.01 per share, with a Black-Scholes value of $413,690 and a term of
2 years. Variables used in the valuation include (1) discount rate of 0.26%, (2) expected life of 2 years, (3) expected volatility
of 242.0% and (4) zero expected dividends. (see Note 6 – Debt).
On
December 27, 2012, we issued a warrant to purchase 100,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes
value of $89,952 and a term of 5 years, to the placement agent for the Note Purchase Agreement and amended the term of the warrant
granted on April 27, 2012 from two to five years, with a Black-Scholes value of $1,161. Variables used in the valuation include
(1) discount rate of 0.72%, (2) expected life of 5 years, (3) expected volatility of 242.0% and (4) zero expected dividends.
Equity
Compensation Plans
In
June 2007, we implemented the 2007 Osage Exploration and Development, Inc. Equity-Based Compensation Plan (the “Plan”)
which allows the reservation of 5,000,000 shares under the Plan. Under this Plan, securities issued may include options, stock
appreciation rights (“SARs”) and restricted stock. No securities have yet been issued under this plan since inception.
4.
SEGMENT AND GEOGRAPHICAL INFORMATION
At
December 31, 2013, the Company’s continuing operations comprised one segment in one geographic region.
5.
OIL AND GAS PROPERTIES
Oil
and gas properties consisted of the following as of December 31, 2013 and 2012:
| | |
December
31 2013 | | |
December
31, 2012 | |
| | |
| | |
| |
| Properties
subject to amortization | |
$ | 25,551,336 | | |
$ | 8,140,918 | |
| Properties
not subject to amortization | |
| 1,784,465 | | |
| 1,362,235 | |
| Capitalized
asset retirement costs | |
| 3,659 | | |
| 19 | |
| Accumulated
depreciation and depletion | |
| (2,606,243 | ) | |
| (310,097 | ) |
| Oil
& gas properties, net | |
$ | 24,733,217 | | |
$ | 9,193,075 | |
Depreciation
and depletion expense for oil and gas properties totaled $2,308,064 and $298,179 in 2013 and 2012, respectively.
On
April 21, 2011, the Company entered into a participation agreement (“Participation Agreement”) with Slawson Exploration
Company (“Slawson”) and U.S. Energy Development Corporation (“USE,” Slawson and USE, together, the “Parties”).
Pursuant to the terms of the Participation Agreement, Slawson and USE acquired 45% and 30% respectively, of our 10,000 acre Nemaha
Ridge prospect in Logan County, Oklahoma for $4,875,000. In addition, the Parties carried Osage for 7.5% of the cost of the first
three horizontal Mississippian wells, which means that for the first three horizontal Mississippian wells, the Company provided
up to 17.5% of the total well costs. After the first three wells, the Company is responsible for up to 25% of the total well costs.
Revenue from wells drilled pursuant to the Participation Agreement, after royalty payments, is allocated 45% to Slawson, 30% to
USE and 25% to Osage. Slawson was the operator of all wells in the Nemaha Ridge prospect in sections where the Parties’
acreage controlled the section. In sections where the Parties’ acreage does not control the section, we may elect to participate
in wells operated by others.
On
December 12, 2013, Osage and Slawson entered into an agreement (the “Partition Agreement”) which amended the Participation
Agreement related to certain lands located within the Nemaha Ridge in Logan County, Oklahoma, and for the exploration and development
of those leases by the Parties.
Under
the Partition Agreement and effective as of September 1, 2013, Slawson agreed to assign all of its rights, title and interest
in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to
Osage and Osage agreed to assign all of its rights, title and interest in and to the oil and gas leases and force-pooled acreage
which are part of the Nemaha Ridge Project within certain sections to Slawson, such that the net acreage controlled by the parties
would remain substantially unchanged, but that the acreage controlled by each of the parties in undeveloped sections would be
located in sections where the other party did not control acreage. The parties also agreed that the Participation Agreement would
terminate as to all lands within the Nemaha Ridge Project except for lands within sections already developed by the parties which
shall continue to be controlled by the Participation Agreement.
As
a result of the Partition Agreement, Osage has become the project operator on a majority of its acreage in the Nemaha Ridge Project.
As of December 31, 2013, Osage operated approximately 5,014 net acres (9,734 gross) in thirty sections, and remains joint-venture
partners with the Slawson in approximately 4,181 net acres (26,823 gross) across forty-five sections.
In
2011, the Company began to acquire leases in Pawnee County, Oklahoma, targeting the Mississippian formation. In July 2011, we
purchased from B&W Exploration, Inc. (“B&W”) the Pawnee County prospect targeting the Mississippian, for $8,500.
In addition, B&W is also entitled to an overriding royalty interest on the leases acquired and a 12.5% carry on the first
$200,000 of lease bonus paid in the form of an assignment of 12.5% of the leases acquired. Subsequently, B&W shall have an
option to purchase a 12.5% share of leasehold acquired on a heads-up basis. As of December 31, 2013, the Company had 4,190 net
acres (5,085 gross) leased in Pawnee County. As of December 31, 2013, none of these leases have been assigned to B&W.
In
2011, we also began to acquire leases in Coal County, Oklahoma, targeting the Oily Woodford Shale formation. The Oily Wood ford
Shale formation is located mainly in southeastern Oklahoma in the Arkoma Basin. The Oily Woodford shale lies directly under the
Mississippian and started as a vertical play, but horizontal drilling techniques and multi-stage fracturing technology have been
used in the Woodford in recent years with much success. At December 31, 2013, we had 4,253 net (9,509 gross) acres leased in Coal
County.
At
December 31, 2013, we have leased 51,151 gross (17,638 net) acres across three counties in Oklahoma as follows:
| | |
Gross | | |
Osage
Net | |
| Logan
(non operated) | |
| 26,823 | | |
| 4,181 | |
| Logan | |
| 9,734 | | |
| 5,014 | |
| Coal | |
| 9,509 | | |
| 4,253 | |
| Pawnee | |
| 5,085 | | |
| 4,190 | |
| | |
| 51,151 | | |
| 17,638 | |
6.
DEBT
Apollo
- Note Purchase Agreement
On
April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement (“Note Purchase Agreement” or
“Notes”) with Apollo Investment Corporation (“Apollo”). The Notes, which mature on April 27, 2015, are
secured by substantially all of the assets of the Company, including a mortgage on all our Oklahoma leases. The Notes bear interest
of Libor plus 15.0% with a Libor floor of 2.0%, with interest payable monthly. In addition, Apollo received a warrant to purchase
1,496,843 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $2,483,952 and an expiration date
of April 27, 2017. Variables used in the valuation include (1) discount rate of 0.82%, (2) expected life of 5 years, (3) expected
volatility of 245.0% and (4) zero expected dividends. The minimum draw amount on the Note Purchase Agreement is $1,000,000. At
closing, we did not draw down any funds.
At
closing of the Note Purchase Agreement, we paid $100,000 of a minimum placement fee to CC Natural Resource Partners, LLC (“CCNRP”)
and issued a warrant to purchase 250,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of
$413,690 and an expiration date of April 27, 2014. Variables used in the valuation include (1) discount rate of 0.26%, (2) expected
life of 2 years, (3) expected volatility of 242.0% and (4) zero expected dividends. In addition, we paid $170,692 in legal fees,
of which $100,000 were paid to Apollo. In December 2012, we paid an additional $380,000 in placement fees. We also issued a warrant
to purchase 100,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $89,952 and a term of
five years, to the placement agent for the Note Purchase Agreement and amended the term of the warrant granted on April 27, 2012
from two to five years, with a Black-Scholes value of $1,161. Variables used in the valuation include (1) discount rate of 0.72%,
(2) expected life of five years, (3) expected volatility of 242.0% and (4) zero expected dividends. In December 2013 we paid an
additional $100,000 in placement fees.
On
April 5, 2013 the Company and Apollo amended the Note Purchase Agreement, increasing the amount of the facility to $20,000,000
and modifying certain covenants for the remainder of the Note Purchase Agreement term. The amendment also provided a waiver of
certain covenants as of March 31, 2013, as the Company did not meet certain covenants including the minimum production covenant
as of that date. The Company paid an amendment fee of $100,000 which is being amortized over the remaining term of the Note Purchase
Agreement.
On
August 12, 2013, the Company and Apollo amended the Note Purchase Agreement. The amendment required that the Company, within 75
days of the effective date as defined in the amendment, complete either (1) a sale of certain assets, or (2) the issuance of capital
stock in a transaction that resulted in aggregate net proceeds as defined in the amendment. In the event that the Company did
not complete either one of the aforementioned transactions, the Company would have been required under the terms of the amendment
to issue to Apollo additional warrants equivalent to three percent of the Company’s common stock, on a fully-diluted basis.
On October 7, 2013, the Company completed the sale of its membership interests in Cimarrona LLC as more fully discussed in Note
13. This sale satisfied the requirements of the amendment and the Company is thus not obligated to issue additional Warrants to
Apollo.
During
the year ended December 31, 2013, we drew down $17,000,000 and, as of December 31, 2013, the amount outstanding under the Note
Purchase Agreement was $20,000,000.
The
Company has recorded deferred financing costs in the aggregate amount of $3,859,448 in connection with the Note Purchase Agreement,
which represented the fair value of warrants issued to Apollo and CCNRP, placement fees, amendment fees and legal fees, which
are amortized on a straight-line basis over the term of the Notes as the Company did not draw funds at issuance.
On
each anniversary of the closing date, the Company is obligated to pay an administrative fee of $50,000. The Company is also obligated
to pay a quarterly standby fee, which accrues at a rate of 3.0%, on the amount of undrawn funds equal to the difference between
$5,000,000 and the aggregate principal amount of notes issued on or after the closing date. The Company is subject to certain
precedents in connection with each draw, an upfront fee equal to 2.0% of the principal amount of each draw, and is required to
maintain a deposit account equal to three months of interest payments.
The
Company is subject to various affirmative, negative and financial covenants under the Note Purchase Agreement as amended along
with other restrictions and requirements, all as defined in the Note Purchase Agreement. Affirmative covenants include by October
31st of each year beginning in 2012, a reserve report prepared as of the immediately preceding September 30, concerning the Company’s
domestic oil and gas properties prepared by approved petroleum engineers, and thereafter as of September 30th of each year. Financial
covenants include the following:
| |
|
|
|
Minimum |
|
|
| |
|
Interest |
|
Production |
|
Asset
Coverage |
| Each
Quarter Ending: |
|
Coverage
Ratio |
|
(MBbls) |
|
Ratio |
| March
31, 2014 |
|
2.50
to 1.00 |
|
70 |
|
1.75
to 1.00 |
| June
30, 2014 |
|
3.00
to 1.00 |
|
80 |
|
2.00
to 1.00 |
| September
30, 2014 |
|
3.00
to 1.00 |
|
90 |
|
2.00
to 1.00 |
| December
31, 2014, and thereafter |
|
3.00
to 1.00 |
|
100 |
|
2.00
to 1.00 |
As
of December 31, 2013, as a result of production delays outside of the Company’s control, the Company was not in compliance
with certain covenants including the minimum production covenant. The Company believes Apollo will provide a waiver of these covenants
as of that date. The Company has classified amounts outstanding under the Note Purchase Agreement as short term in the accompanying
consolidated financial statements.
Use
of proceeds is limited to those purposes specified in the Note Purchase Agreement. The Notes are subject to mandatory prepayment
in the event of certain asset sales, insurance or condemnation proceeds, issuance of indebtedness, extraordinary receipts and
tax refunds. All terms are as defined in the Note Purchase Agreement.
Boothbay
- Secured Promissory Note
On
April 17, 2012, we issued a secured promissory note (“Secured Promissory Note”) to Boothbay Royalty Co., (“Boothbay”)
for gross proceeds of $2,500,000. The Secured Promissory Note had a maturity date of April 17, 2014 and bore interest of 18%,
payable monthly. In addition, Boothbay received 400,000 shares of common stock for which the relative fair value of $386,545 was
recorded as debt discount, a 1.5% overriding royalty on our leases in section 29, township 17 North, range 3 and a 1.7143% overriding
royalty on our leases in section 36, township 19 North, range 4 West in Logan County, Oklahoma. The closing price of the Company’s
common stock on April 17, 2012 was $1.14. The Secured Promissory Note was secured by a first mortgage (with power of sale), security
agreement and financing statement covering a 5% overriding royalty interest, proportionately reduced, in all of the Company’s
leases in Logan County, Oklahoma. The Company repaid the Secured Promissory Note in full in December 2013.
In
connection with the Note Purchase Agreement, Secured Promissory Note and certain terms of the Partition Agreement with Slawson,
the Company recognized $4,566,246 of interest expense, of which $2,999,838 was cash interest expense, for the year ended December
31, 2013. Non-cash interest expense related to the Note Purchase Agreement and the Secured Promissory Note represented $1,295,348
and $271,060 for the year ended December 31, 2013. The Company recognized $1,288,841 of interest expense, of which $538,889 was
cash interest expense, for the year ended December 31, 2012. Non-cash interest expense related to the Note Purchase Agreement
and the Secured Promissory Note represented $734,976 and $114,596 for the year ended December 31, 2012.
7.
DERIVATIVE FINANCIAL INSTRUMENTS
The
Company entered into certain derivative financial instruments with respect to a portion of its oil and gas production in the year
ended December 31, 2013. Prior thereto, the Company had not entered into any derivative financial instruments. These instruments
are used to manage the inherent uncertainty of future revenues due to commodity price volatility and currently include only costless
price collars. The Company does not intend to hold or issue derivative financial instruments for speculative trading purposes
and has elected not to designate any of its derivative instruments for hedge accounting treatment.
As
of December 31, 2013, the Company had the following open oil derivative positions. These oil derivatives settle against the average
of the daily settlement prices for the WTI first traded contract month on the New York Mercantile Exchange (“NYMEX”)
for each successive day of the calculation period.
| | |
Price
Collars | |
| | |
Monthly | | |
Weighted
Average | | |
Weighted
Average | |
| | |
Volume | | |
Floor
Price | | |
Ceiling
Price | |
| Period | |
| (BBLs/m) | | |
| ($/BBL) | | |
| ($/BBL) | |
| | |
| | | |
| | | |
| | |
| Q1
- Q4, 2014 | |
| 6,000 | | |
$ | 85.00 | | |
$ | 95.00 | |
| Q1 - Q2, 2015 | |
| 6,000 | | |
$ | 80.00 | | |
$ | 93.50 | |
As
of December 31, 2013, the Company had the following open natural gas derivative positions. These natural gas derivatives settle
against the NYMEX Penultimate for the calculation period.
| | |
Price
Collars | |
| | |
Monthly | | |
Weighted Average | | |
Weighted Average | |
| | |
Volume | | |
Floor Price | | |
Ceiling Price | |
| Period | |
(Btu/m) | | |
($/Btu) | | |
($/Btu) | |
| | |
| | |
| | |
| |
| Q1 - Q4, 2014 | |
| 10,000 | | |
$ | 3.75 | | |
$ | 4.40 | |
| Q1 - Q2, 2015 | |
| 10,000 | | |
$ | 3.75 | | |
$ | 4.40 | |
Cash
settlements and unrealized gains and losses on fair value changes associated with the Company’s commodity derivatives are
presented in the “Loss on oil and gas derivatives” caption in the accompanying consolidated statements of operations.
The
following table sets forth the cash settlements and unrealized gains and losses on fair value changes for commodity derivatives
for the year ended December 31, 2013.
| | |
Year
Ended | |
| | |
December
31, 2013 | |
| | |
| |
| Cash
settlements to (by) Company | |
$ | (138,236 | ) |
| Unrealized
gains (losses) on commodity derivatives | |
| (357,567 | ) |
| | |
| | |
| Loss
on oil and gas derivatives | |
$ | (495,803 | ) |
On
October 15, 2013, the Company entered into an Intercreditor Agreement with Apollo and BP Energy Company to provide collateral
for its oil and gas derivative financial instruments. BP Energy Corporation North America simultaneously provided a Guarantee
for $25 million as collateral for its obligations to the Company.
8.
COMMITMENTS AND CONTINGENCIES
ENVIRONMENT
Osage,
as owner and operator of oil and gas fields, is subject to various federal, state, and local laws and regulations relating to
discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability
on the owner of real property and the lessee under oil and gas leases for the cost of pollution clean-up resulting from operations,
subject the owner/lessee to liability for pollution damages and impose restrictions on the injection of liquids into subsurface
strata.
Although
Company environmental policies and practices are designed to ensure compliance with these laws and regulations, future developments
and increasing stringent regulations could require the Company to make additional unforeseen environmental expenditures
The
Company maintains insurance coverage that it believes is customary in the industry, although it is not fully insured against all
environmental risks.
The
Company is not aware of any environmental claims existing as of December 31, 2013, that would have a material impact on its consolidated
financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not
change, or past non-compliance with environmental laws will not be discovered on the Company’s property.
OPERATING
LEASES
In
February 2011, the Company entered into a 36 month lease for its corporate offices in San Diego. In February 2014 the Company
amended this lease to extend the term for an additional three years through February 2017. In February 2012, the Company entered
into a 24 month lease for a vehicle to be utilized by its operations in Oklahoma. In December 2013, the Company entered into a
three year lease for office space in Oklahoma City.
Rental
expense totaled $58,147 and $57,344 in 2013 and 2012, respectively.
Future
minimum commitments under operating leases are as follows as of December 31, 2013:
| Year | |
Amount | |
| | |
| |
| 2014 | |
$ | 157,787 | |
| 2015 | |
| 170,530 | |
| 2016 | |
| 171,818 | |
| 2017 | |
| 28,672 | |
| | |
$ | 528,807 | |
LEGAL
PROCEEDINGS
The
Company is not a party to any litigation that has arisen in the normal course of its business or that of its subsidiaries.
Division
de Impuestos y Actuanas Nacionales (“DIAN”), the Colombian tax authorities, levies a tax based on the equity value
of Cimarrona. In 2010, the Company was notified by DIAN that it owed $883,742 in equity taxes relating to the 2001 and 2003 equity
tax years. To compute the value the equity tax is assessed upon, Cimarrona subtracted the cost of its non-producing wells in 2001
and 2003. However, DIAN’s position is that as long as the field is productive, Cimarrona should not have subtracted the
cost of the non-producing wells. In May 2011, we settled in full the 2001 equity liability with DIAN. In January 2012, we were
informed by DIAN that we had lost our appeal on the 2003 tax issue and we increased the amount attributable to the 2003 tax year
by $322,288 as of December 31, 2011 to correspond to the amount DIAN indicated we owed for the 2003 tax year. In January 2013,
we successfully concluded negotiations with DIAN with respect to the ultimate liability for the 2003 tax year. DIAN waived certain
interest and penalties. We paid the agreed final liability to DIAN in January 2013, and financed the payment with an unsecured
Colombian term loan facility in the amount of $367,521. We recognized in discontinued operations the $531,644 benefit of the amnesty
in the quarter ended June 30, 2013, upon receipt of official confirmation that the liability is fully settled.
SALE
OF CIMARRONA LLC
On
October 7, 2013, the Company completed the sale of 100% of the membership interests in Cimarrona LLC to Raven Pipeline Company,
LLC (“Raven”), pursuant to a Membership Interest Purchase Agreement dated September 30, 2013 (the “Agreement”)
by and between the Company and Raven. The Cimarrona property is subject to an Ecopetrol Association Contract (the “Association
Contract”) whereby Ecopetrol S.A. (“Ecopetrol”) receives royalties of 20% of the oil produced. The pipeline
is not subject to the Association Contract. In addition to the royalty, according to the Association Contract, Ecopetrol may,
for no consideration, become a 50% partner, once an audit of revenues and expenses indicate that the partners in the Association
Contract have received a 200% reimbursement of all historical costs to develop and operate the Guaduas field. If such an audit
determines that the specified reimbursement of historical costs occurred prior to September 30, 2013, the Company is required
to reimburse Raven for any amounts due to Ecopetrol from Cimarrona LLC which relate to the period prior to that date. The Company
believes its maximum exposure is 50% of Cimarrona LLC’s oil revenues for the nine months ended September 30, 2013, or $729,308.
The Company has not recorded any provision for this matter, as it is not possible to estimate the potential liability, if any.
9.
DILUTIVE SECURITIES
As
of December 31, 2013 and 2012, the Company had outstanding dilutive securities, consisting entirely of warrants. Changes in warrants
outstanding are as follows:
| | |
Shares | | |
Weighted
Average Exercise Price | | |
Average
Remaining Contractual Life |
| Balance
December 31, 2011 | |
| 1,125,000 | | |
$ | 1.25 | | |
1.75
years |
| Granted | |
| 2,246,843 | | |
$ | 0.01 | | |
|
| Exercised | |
| (200,000 | ) | |
$ | 0.01 | | |
|
| Balance
December 31, 2012 | |
| 3,171,843 | | |
$ | 0.45 | | |
2.72 years |
| Exercised | |
| (350,000 | ) | |
$ | 0.01 | | |
|
| Cancelled
or Expired | |
| (1,125,000 | ) | |
$ | 1.25 | | |
|
| Balance
December 31, 2013 | |
| 1,696,843 | | |
$ | 0.01 | | |
3.35 years |
The
intrinsic value of these dilutive securities as of December 31, 2013 was $1,662,906.
10.
INCOME TAXES
The
total provision for income taxes consists of the following in 2013 and 2012:
| | |
Year
Ended December
31, | |
| | |
2013 | | |
2012 | |
| Current
Taxes: | |
| | | |
| | |
| Federal | |
$ | - | | |
$ | - | |
| State | |
| - | | |
| - | |
| Foreign | |
| - | | |
| - | |
| | |
| - | | |
| - | |
| | |
| | | |
| | |
| Deferred
Taxes: | |
| | | |
| | |
| Federal | |
| 646,907 | | |
| 180,847 | |
| State | |
| 60,070 | | |
| 16,793 | |
| Foreign | |
| - | | |
| - | |
| | |
| | | |
| | |
| Valuation
Allowance | |
| (706,977 | ) | |
| (197,640 | ) |
| | |
| - | | |
| - | |
| Totals | |
$ | - | | |
$ | - | |
Following
is a reconciliation of the Federal statutory rate to the effective income tax rate for 2013 and 2012:
| | |
2013 | | |
2012 | |
| Computed
tax provision at statutory Federal rates | |
| 35.0 | % | |
| 35.0 | % |
| Increase
(decrease) in taxes resulting from: | |
| | | |
| | |
| State
taxes, net of Federal income tax benefit | |
| 3.25 | % | |
| 3.25 | % |
| Nondeductible
and other expenses | |
| -4.33 | % | |
| -130.45 | % |
| Federal
and State true ups | |
| 0.0 | % | |
| 0.0 | % |
| Other
adjustments | |
| -15.52 | % | |
| 0.0 | % |
| Valuation
Allowance | |
| -18.4 | % | |
| 92.2 | % |
| | |
| 0.0 | % | |
| 0.0 | % |
At
December 31, 2013, the Company had federal and state net operating loss carry forwards of approximately $9.9 million which expire
at various dates through 2032.
Pursuant
to Internal Revenue Code Sections 382 and 383, use of the Company’s net operating loss and credit carryforwards may be limited
if a cumulative change in ownership of more than 50% occurs within a three-year period. These financial statements do not contain
any adjustment relating to such potential limitations. The Company is subject to tax in the United States and in the state of
California. As of December 31, 2013, the Company’s tax years from 2010 are subject to examination by the tax authorities.
The Company is not currently under examination by any U.S. federal or state jurisdictions.
Deferred
tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities
for financial reporting purposes and amounts used for income tax purposes. Significant components of Osage’s deferred tax
assets and liabilities are as follows at December 31, 2013 and December 31, 2012:
| | |
2013 | | |
2012 | |
| Deferred tax
liability: | |
| | | |
| | |
| | |
| | | |
| | |
| Net
operating loss carry forward | |
$ | 3,807,000 | | |
$ | 2,772,000 | |
| Other | |
| 879,000 | | |
| 5,000 | |
| Oil and gas
properties | |
| (4,501,000 | ) | |
| (1,837,000 | ) |
| Valuation
allowance | |
| (185,000 | ) | |
| (940,000 | ) |
| Net
deferred tax liability | |
| - | | |
| - | |
The
non-current portions of the deferred tax asset and the deferred tax liability accounts offset each other in the Company’s
consolidated balance sheet.
11.
MAJOR CUSTOMERS
During
2013 and 2012, four and three customers, respectively, accounted for all of the Company’s sales from continuing operations:
| | | |
Year
ended December 31, 2013 | | |
Year
ended December 31, 2012 | |
| | | |
Amount | | |
%
of Total | | |
Amount | | |
%
of Total | |
| Slawson | | |
$ | 6,421,674 | | |
| 80.0 | % | |
$ | 2,205,088 | | |
| 97.4 | % |
| Stephens | | |
| 847,573 | | |
| 10.6 | % | |
| - | | |
| 0.0 | % |
| Devon | | |
| 738,178 | | |
| 9.2 | % | |
| 14,766 | | |
| 0.7 | % |
| Sundance | | |
| 21,663 | | |
| 0.3 | % | |
| - | | |
| 0.0 | % |
| Coffeyville | | |
| - | | |
| 0.0 | % | |
| 44,159 | | |
| 2.0 | % |
| Total | | |
$ | 8,029,088 | | |
| 100.0 | % | |
$ | 2,264,013 | | |
| 100.0 | % |
12.
LIABILITY FOR ASSET RETIREMENT OBLIGATIONS
The
Company recognizes a liability at discounted fair value for the future retirement of tangible long-lived assets and associated
assets retirement cost associated with the oil and natural gas properties. The fair value of the liability is capitalized as part
of the cost of the related asset and amortized to expense over its useful life. The liability accretes until the date of expected
settlement of the retirement obligations. The related accretion expense is recognized in the statement of operations. The provision
will be revised for the effect of any changes to timing related to cash flow or undiscounted abandonment costs. Actual expenditures
incurred for the purpose of site reclamation are charged to the asset retirement obligations to the extent that the liability
exists on the balance sheet. Differences between the actual costs incurred and the fair value of the liability recorded are recognized
in income in the period the actual costs are incurred. There are no legally restricted assets for the settlement of asset retirement
obligations. No income tax is applicable to the asset retirement obligation as of December 31, 2013 and 2012, because the Company
records a valuation allowance on deductible temporary differences due to the uncertainty of its realization. A reconciliation
of the Company’s asset retirement obligations from the periods presented is as follows:
| | |
Year
Ended December 31, | |
| | |
2013 | | |
2012 | |
| Beginning
balance | |
$ | 19 | | |
$ | 24,231 | |
| Incurred
during the period | |
| - | | |
| - | |
| Reversed
during the period | |
| - | | |
| (24,231 | ) |
| Additions
for new wells | |
| 3,639 | | |
| 19 | |
| Accretion
expense | |
| 228 | | |
| - | |
| Ending
balance | |
$ | 3,886 | | |
$ | 19 | |
13.
DISCONTINUED OPERATIONS
On
October 7, 2013, the Company completed the sale of 100% of the membership interests in Cimarrona LLC to Raven, pursuant to the
Agreement dated September 30, 2013 by and between the Company and Raven. Cimarrona LLC is the owner of a 9.4% interest in certain
oil and gas assets including a pipeline in the Guaduas field, located in the Dindal and Rio Seco Blocks that covers 30,665 acres
in the Middle Magdalena Valley in Colombia.
The
sales price consisted of cash of $6,800,000, less settlement of debt of Cimarrona LLC of approximately $250,000. Of the net sales
price, $250,000 will be held in escrow for 12 months to secure any post-Closing purchase price adjustments and any indemnity obligations
of the Company pursuant to the Agreement. In addition, so long as the per barrel transportation rate charged with respect to the
pipeline is not adjusted prior to March 31, 2014, then Raven will pay the Company an additional $1,000,000 in cash. Pursuant to
the Agreement, the Company also recognized a receivable for a working capital adjustment of $422,955 in other current assets as
of December 31, 2013 and recognized a gain on disposal of discontinued operations of $4,873,660 in the year ended December 31,
2013.
Accordingly,
the assets and liabilities of the Colombian operations are classified as Held for Sale in the balance sheet as of December 31,
2012, with the exception of cash of $150,950.
The
following table sets forth the results of operations for the discontinued operations for the periods presented:
| | |
Year
Ended December 31, | |
| | |
2013 | | |
2012 | |
| Revenues | |
| | | |
| | |
| Oil
revenues | |
$ | 1,458,616 | | |
$ | 1,943,070 | |
| Pipeline
revenues | |
| 1,828,256 | | |
| 1,912,941 | |
| Total
revenues | |
| 3,286,872 | | |
| 3,856,011 | |
| | |
| | | |
| | |
| Operating
costs and expenses | |
| | | |
| | |
| Operating
expenses | |
| 1,007,987 | | |
| 1,554,039 | |
| Depreciation,
depletion and accretion | |
| 124,193 | | |
| 254,237 | |
| Equity
tax | |
| (435,988 | ) | |
| 131,186 | |
| General
and administrative | |
| 72,756 | | |
| 54,311 | |
| Total
operating costs and expenses | |
| 768,948 | | |
| 1,993,773 | |
| | |
| | | |
| | |
| Operating
income | |
| 2,517,924 | | |
| 1,862,238 | |
| | |
| | | |
| | |
| Other
income (expenses): | |
| | | |
| | |
| Interest
income | |
| 103 | | |
| 1,189 | |
| Interest
expense | |
| (21,486 | ) | |
| - | |
| Income
before income taxes | |
| 2,496,541 | | |
| 1,863,427 | |
| Provision
for income taxes | |
| - | | |
| - | |
| Net
income | |
$ | 2,496,541 | | |
$ | 1,863,427 | |
The
following table sets forth balance sheet information for the discontinued operations as of December 31, 2012:
| | |
As
of | |
| | |
December
31, 2012 | |
| Accounts
receivable | |
| 114,568 | |
| Short
term assets held for sale | |
| 114,568 | |
| | |
| | |
| Oil
and gas properties | |
| 2,979,980 | |
| Less
accumulated depletion, depreciation and amortization | |
| (1,690,707 | ) |
| Long
term assets held for sale | |
| 1,289,273 | |
| | |
| | |
| Accounts
payable | |
| 18,786 | |
| Accrued
expenses | |
| 1,306,501 | |
| Short
term liabilities held for sale | |
| 1,325,287 | |
The
Cimarrona property is subject to an Association Contract whereby Ecopetrol receives royalties of 20% of the oil produced. The
pipeline is not subject to the Association Contract. In addition to the royalty, according to the Association Contract, Ecopetrol
may, for no consideration, become a 50% partner, once an audit of revenues and expenses indicate that the partners in the Association
Contract have received a 200% reimbursement of all historical costs to develop and operate the Guaduas field. If such an audit
determines that the specified reimbursement of historical costs occurred prior to September 30, 2013, the Company is required
to reimburse Raven for any amounts due to Ecopetrol from Cimarrona LLC which relate to the period prior to that date.
The Company believes its maximum
exposure is 50% of Cimarrona LLC’s oil revenues for the nine months ended September 30, 2013, or $729,308. The Company has
not recorded any provision for this matter, as it not possible to estimate the potential liability, if any.
14.
SUBSEQUENT EVENTS
In
February 2014, the Company initiated a private placement, pursuant to Securities Purchase Agreements between Osage and certain
purchasers, with aggregate gross proceeds of approximately $6.5 million. The purchase price of each unit, representing one share
of common stock and a warrant to purchase 0.4 shares of common stock at $1.80 per share, was $0.90. The warrants have a term of
five years. The placement agent will receive placement fees of 8%, in cash or warrants or a combination thereof at their election.
15.
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
There are numerous uncertainties inherent
in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures,
including many factors beyond the control of the Company and the operators. The reserve data set forth in this Supplemental Information
to Consolidated Financial Statements represent only estimates. Reserve engineering is a subjective process of estimating underground
accumulations of crude oil and condensate, natural gas liquids and natural gas that cannot be measured in an exact manner. The
accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation
and judgment. As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production
subsequent to the date of an estimate may justify revision of such estimate upward or downward. Accordingly, reserve estimates
are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the
accuracy of the assumptions upon which they were based.
Management maintains internal controls
designed to provide reasonable assurance that the estimates of proved reserves are computed and reported in accordance with rules
and regulations as promulgated by the SEC. The Company retained Pinnacle Energy Services, LLC (“Pinnacle”) to independently
prepare estimates of our oil and gas reserves in our properties in Logan County, Oklahoma. Management is responsible for providing
the following information related to our oil and gas properties to the firm: working and net revenue interests, historical production
rates, current operating and future development costs, and geoscience, engineering and other information. Our Chief Geologist
reviews the final reserve estimate for completeness and reasonableness and, if necessary, discusses the process used and findings
with the designated technical person at Pinnacle. Our Chief Geologist has over 25 years of oil and gas experience. The technical
person primarily responsible for audit of our reserve estimates at Pinnacle meets the requirements regarding qualifications, independence,
objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves
Information promulgated by the Society of Petroleum Engineers. Pinnacle is an independent firm of petroleum engineers, geologists,
geophysicists, and petro physicists; they do not own an interest in our properties and are not employed on a contingent fee basis.
Reserve estimates are imprecise and subjective and may change at any time as additional information becomes available. Furthermore,
estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation
of this data as well as the projection of future rates of production. The accuracy of any reserve estimate is a function of the
quality of available data and of engineering and geological interpretation and judgment.
Pinnacle
prepared reserve estimates for the year end reports for 2013 and 2012 for our continuing operations in Logan County, Oklahoma.
For wells on production with sufficient historical data, remaining reserves were determined by decline curve analysis. For
wells with limited production or pressure data history and those with definable reserves using offset well and reservoir parameters,
remaining reserves were estimated based on analogy well and test data and other available geological and engineering information.
Proved
oil and gas reserves are the estimated quantities of crude oil, condensate, natural gas and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.
Proved
developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods.
FASB
ASC Topic 932, “Financial Accounting and Reporting by Oil and Gas Producing Companies”, requires disclosure of certain
financial data for oil and gas operations and reserve estimates or oil and gas. This information, presented here is intended to
enable the reader to better evaluate the operations of the Company. All of the Company’s oil and gas reserves from continuing
operations are located in the United States.
The
aggregate amount of capitalized costs relating to oil and gas producing activities and the related accumulated depletion, depreciation,
amortization and valuation allowances as of December 31, 2013 and 2012 are as follows:
| | |
2013 | | |
2012 | |
| Proved
properties | |
$ | 25,551,336 | | |
$ | 8,140,819 | |
| Unproved properties
being amortized | |
| - | | |
| - | |
| Unproved properties
not being amortized | |
| 1,784,465 | | |
| 1,362,235 | |
| Capitalised
asset retirement costs | |
| 3,659 | | |
| 1
9 | |
| Accumulated
depletion, depreciation | |
| | | |
| | |
| amortization
and valuation allowances | |
| (2,606,243 | ) | |
| (310,097 | ) |
| | |
$ | 24,733,217 | | |
$ | 9,192,976 | |
Estimated
quantities of proved developed and undeveloped reserves of crude oil, natural gas and natural gas liquids, as well as changes
in proved developed and undeveloped reserves for our continuing operations during the past two years are indicated below.
| | |
Oil
(BBLS) | | |
Gas
(MMCF) | | |
Natural
Gas Liquids (BBLs) | |
| | |
2013 | | |
2012 | | |
2013 | | |
2012 | | |
2013 | | |
2012 | |
| Proved developed
and undeveloped reserves: | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| Beginning
of year | |
| 364,000 | | |
| 113,193 | | |
| 1,499 | | |
| 201 | | |
| - | | |
| - | |
| Revisions
of previous estimates | |
| - | | |
| - | | |
| | | |
| - | | |
| - | | |
| - | |
| Improved
recovery | |
| - | | |
| - | | |
| | | |
| - | | |
| - | | |
| - | |
| Purchases
of Minerals in place | |
| - | | |
| - | | |
| | | |
| - | | |
| - | | |
| - | |
| Extensions
and discoveries | |
| 1,220,409 | | |
| 385,427 | | |
| 5,016 | | |
| 1,561 | | |
| 46,507 | | |
| - | |
| Production | |
| (76,409 | ) | |
| (22,057 | ) | |
| (150 | ) | |
| (62 | ) | |
| (3,507 | ) | |
| - | |
| Sales
of minerals in place | |
| - | | |
| (112,563 | ) | |
| - | | |
| (201 | ) | |
| - | | |
| - | |
| End of year | |
| 1,508,000 | | |
| 364,000 | | |
| 6,365 | | |
| 1,499 | | |
| 43,000 | | |
| - | |
| | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| Proved developed
reserves: | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| Beginning
of year | |
| 195,000 | | |
| 113,193 | | |
| 803 | | |
| 201 | | |
| - | | |
| - | |
| End of year | |
| 460,000 | | |
| 195,000 | | |
| 2,005 | | |
| 803 | | |
| 33,000 | | |
| - | |
| | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| Proved undeveloped reserves: | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| Beginning of year | |
| 169,000 | | |
| - | | |
| 696 | | |
| - | | |
| - | | |
| - | |
| End of year | |
| 1,048,000 | | |
| 169,000 | | |
| 4,360 | | |
| 696 | | |
| 10,000 | | |
| - | |
All changes in estimated proved developed
and proved undeveloped reserves during 2013 were as a result of extensions and discoveries. In December 2011, the Company commenced
drilling its first development well in Logan County and incurred $17,891,932 during 2013 in capital expenditures for oil and gas
related properties. We participated in the drilling and completion of 35 productive development wells during 2013 and had participated
in the drilling and completion of 40 productive development wells as of December 31, 2013.
The
foregoing estimates have been prepared by Pinnacle for the Logan County, Oklahoma property. The reserve estimates
are believed to be reasonable and consistent with presently known physical data concerning size and character of the reservoirs
and are subject to change as additional knowledge concerning the reservoirs becomes available.
Depletion,
depreciation and accretion per equivalent unit of production was $22.00 and $8.05 for 2013 and 2012.
FASB
ASC Topic 932, “Disclosure About Oil and Gas Producing Activities”, requires certain disclosures of the costs and
results of exploration and production activities and established a standardized measure of oil and gas reserves and the year-to-year
changes therein.
Cost
incurred, both capitalized and expensed, for oil and gas property acquisition, exploration and development for the years
ended December 31, 2013 and 2012 were are follows:
| | |
2013 | | |
2012 | |
| Property
acquisition costs | |
$ | 1,278,408 | | |
$ | 1,821,945 | |
| Development
costs | |
| 16,613,524 | | |
| 5,532,019 | |
| Exploration
costs | |
| - | | |
| - | |
| Asset retirement
costs | |
| - | | |
| - | |
Future
cash inflows were computed by applying the average prices of oil and gas (with consideration of price changes only to the extent
provided by contractual arrangements) and using the estimated future expenditures to be incurred in developing and producing the
proved reserves, assuming the continuation of existing economic conditions.
The
average prices used in the reserve estimate for oil were $96.94 per BBL in 2013 and $94.71 per BBL in 2012. For natural gas, the
average prices used in the reserve estimate were $3.67 per Mcf in 2013 and $2.757 per Mcf in 2012.
Future
income tax expenses were computed by applying statutory income tax rates to the difference between pretax net cash flows related
to the Company’s proved oil and gas reserves and the tax basis of proved oil and gas properties and available operating
loss and excess statutory depletion carryovers reduced by investment tax credits. Discounting the annual net cash flows at 10%
illustrates the impact of timing on these future cash flows.
The
following table presents the standardized measure of discounted estimated net cash flows relating to proved oil and gas reserves
for 2013 and 2012.
| | |
2013 | | |
2012 | |
| Future
cash inflows | |
$ | 176,035,000 | | |
$ | 41,104,970 | |
| Future production
costs | |
| (47,088,610 | ) | |
| (9,538,070 | ) |
| Future development
costs | |
| (35,500,100 | ) | |
| (4,963,580 | ) |
| Future abandonment
costs | |
| (451,200 | ) | |
| (81,600 | ) |
| Future
income tax expenses | |
| (37,198,036 | ) | |
| (10,608,688 | ) |
| | |
| | | |
| | |
| Future net
cash flow | |
| 55,797,054 | | |
| 15,913,032 | |
| 10%
annual discount for estimated timing of cash flows | |
| (29,219,748 | ) | |
| (7,048,928 | ) |
| Standardized
measure of discounted future net cash flow | |
$ | 26,577,306 | | |
$ | 8,864,104 | |
The
principal changes in the standardized measure of discounted future net cash flows during 2013 and 2012 were as follows:
| | |
2013 | | |
2012 | |
| Extensions | |
| - | | |
| 16,612,053 | |
| Revisions
of previous estimates | |
| | | |
| | |
| Price changes | |
$ | 182,220 | | |
$ | - | |
| Quantity
Changes | |
| 105,407,911 | | |
| - | |
| Changes in
production rates, timing and other | |
| (54,058,998 | ) | |
| - | |
| Development
costs incurred | |
| - | | |
| - | |
| Changes in
estimated future development costs | |
| (17,009,887 | ) | |
| - | |
| Purchase of
minerals in place | |
| - | | |
| - | |
| Sales of minerals
in place | |
| - | | |
| (5,284,705 | ) |
| Sales of oil
and gas, net of production costs | |
| (6,481,139 | ) | |
| (1,838,548 | ) |
| Accretion of discount | |
| 1,481,896 | | |
| - | |
| Net
change in income taxes | |
| (11,808,801 | ) | |
| (3,795,520 | ) |
| Net
increase/ (decrease) | |
$ | 17,713,202 | | |
$ | 5,693,280 | |
Exhibit
10.32
PARTICIPATION
AGREEMENT
NEMAHA
RIDGE PROJECT
LOGAN
COUNTY, OKLAHOMA
THIS
PARTICIPATION AGREEMENT (this “Agreement”), entered into this 21st day of April, 2011, is by and between Osage Exploration
& Development, Inc. whose address is 2445 Fifth Avenue Suite 310 San Diego, CA 92101 (hereafter “Osage”) and Slawson
Exploration Company, Inc., a Kansas corporation, whose principal place of business is 727 North Waco, Suite 400, Wichita, Kansas,
67203 (hereafter “SEG”J and U.S. Energy Development Corporation, whose address is 2350 North Forest Road, Getzville,
New York 14068, (hereafter “USE”). SEC! and USE shall sometimes be referred to herein as a “Participant”.
Osage and Participant shall sometimes be referred to herein individually as a “Party” and collectively as the “Parties.”
WHEREAS,
Osage has developed oil and gas leads and acquired certain leasehold interests covering lands within the Nemaha Ridge Project
Area (“Project Area”), located in Logan County, Oklahoma, and described on Exhibit A; and,
WHEREAS,
the leasehold interest leased by Osage is listed on Exhibit B; and,
WHEREAS,
Participants wish to participate with Osage in the leasing, drilling and development of the Project Area pursuant to the provisions
of this Agreement and the agreements through which Osage acquires leasehold rights within the Project Area.
NOW
THEREFORE, the Parties, for the mutual promises contained herein and other good and valuable consideration, the sufficiency of
which is hereby acknowledged, do hereby contract and agree as follows:
| 1. |
Participation
Interest: By execution of this Agreement, SECI and USE acquire the right to participate in and ownership of the following
percentage working interest: |
| |
SECI
forty five percent (45%) |
| |
USE
thirty percent (30%) |
| |
(the
“Participation Interest”) in the exploration and development of the Project Area, subject to adjustment for non-
consent and non-participation elections made by the Parties and other joint interest owners pursuant to the terms of this
Agreement and similar agreements between Osage and other participants. Participants agree that the interest Participants acquire
from Osage within the Project Area shall be specifically subject to the terms of the leases, options, and other agreements
by which the leasehold interests were acquired in the Project Area by Osage, all of which shall be provided to Participants. |
| 2. |
SECI
shall be the “Operator” of all wells in the Project area. |
| |
|
| 3. |
Participants
shall have a 60-day period to conduct due diligence and to confirm title to the acreage to be assigned. The amount payable
to Osage shall be adjusted to account for defects in title to any of the acreage to be acquired at $650 per net acre affected
by a title defect in the reasonable judgment of Participants, or Osage may, within 30 days from notice of a defective lease,
substitute additional leases to account for the 10,000 acres being delivered. |
| |
|
| 4. |
Initial
Payment: Within 30 days of execution of this Agreement, each Participant shall pay Osage each Participant’s Participation
Interest share of the leasehold acquisition costs incurred and paid by Osage through the closing of this Participation Agreement,
at $650.00 per net mineral acre, so long as the total acquired acreage does not exceed 10,000 net acres. |
| |
|
| |
Upon
payment of the sums provided in this paragraph less any allowances for title defects, Osage shall execute and record an assignment
conveying to Participants the Participation Interests in and to the oil and gas leases in the Project Area, including but
not limited to those described on Exhibit “B” hereto. The assignment will be in the form of assignment attached
hereto as Exhibit “D”. Osage shall assign its interest free of any retained override, production payment or net
profits interests or any other burden created by Osage or any affiliate of Osage except as otherwise expressly provided for
herein. THE ASSIGNMENT SHALL BE WITHOUT WARRANTY OF TITLE EITHER EXPRESS OR IMPLIED EXCEPT THAT OSAGE WILL WARRANT TITLE AGAINST
ALL CLAIMS BY, THROUGH OR UNDER OSAGE, and except as otherwise expressly provided for herein. |
| |
|
| 5. |
Participation
Terms: As to the initial three (3) net horizontal Mississippian wells drilled in the Project Area, (the “Initial Wells”),
Participants shall pay Participants’ proportionate share plus ten percent (10%) of expenses chargeable under the relevant
“Operating Agreement,” as that term is hereinafter defined, through the tanks or plugging and abandonment. Thereafter
in each Initial Well and as to all subsequent wells, Participants shall pay their Participation Interest share of all costs
incurred, (without said additional 10%) subject to the additional terms of this Agreement and the applicable Operating Agreement
within the Project Area as to operations in which Participants elect to participate. |
| |
|
| 6. |
Invoicing:
Operator will invoice the Parties monthly for its projected share of the costs incurred or to be incurred in the Project Area
in the succeeding thirty (30) days, and the Parties agree to remit the amount invoiced within thirty (30) days of receipt.
A reconciliation of amounts invoiced on a pre-bill basis per this paragraph and actual costs incurred shall be completed on
a quarterly basis. Any adjustments due by either Party following reconciliation shall be paid within thirty (30) days of the
completion of the reconciliation and notice thereof. |
| 7. |
Drilling
Proposals: Operator shall make a good faith effort to spud the initial well no later than August 1, 2011 and shall prosecute
the drilling of the initial well with reasonable diligence, to the depth (the “Target Depth”) sufficient to test
the Mississippian formation and then commence to drill the lateral as proposed to the Parties. |
| |
|
| |
All
well proposals in the Project Area shall be in writing and identify the location and projected lateral of the well to be drilled,
the objective (or objectives) to be tested, the geological and/or geophysical basis for the proposed well, and an Authority
for Expenditure (“AFE”). The Parties hereto agree to participate in the initial Mississippian test well. Parties
receiving proposals for wells other than the initial Mississippian well will have thirty (30,) days from the date the proposal
is made to either (1) elect to participate as to their working interest in the proposed well, or (2) elect not to participate
in the proposed well. Elections shall be made in writing to the Party proposing the well. Failure to timely elect shall be
deemed to constitute an election not to participate in the proposed well. Any Party electing not to participate in any of
the initial three Mississippian test wells in any areas outlined on Exhibit A shall forfeit all rights within the section
including the drill site plus the 8 sections cornering or adjoining the drill site section and shall reassign to the participating
Party, all such leasehold working interest which it owns in the drill site section plus the 8 sections cornering or adjoining
the drill site section at no cost to the participating Party. Notwithstanding the foregoing, if a Party elects not to participate
in one of the 3 initial wells but has agreed to participate in a previous spacing unit which includes any of the acreage of
the drill site or the 8 sections cornering or adjoining said initial wells, said party shall retain its interest on said previous
spacing unit. |
| |
|
| |
After
the three initial horizontal Mississippian wells have been drilled, or as to any other well that may be proposed other than
a horizontal Mississippian well, should a Party elect not to participate in a well proposed under this paragraph, the forfeiture
shall be a wellbore forfeiture of the drill site wellbore plus one offset location wellbore cornering or adjoining the drill
site (as to acreage located either inside or outside the boundary of an existing spacing unit on which a producing or drilling
well is located, or on which a well has been proposed hereunder, and in which Participant(s) has elected to participate) to
be selected by the participating Party. Notwithstanding the foregoing, however, in order for any such forfeiture to occur
and be binding on the non-participating Party, the participating Parties must proceed to commence and prosecute to conclusion
the operations set out in the AFE and notice within a period of ninety (90) days after the date of the non-consent election
of the notified Parties. The provisions of this paragraph supersede the penalty provisions of the Operating Agreement for
failure to participate in a proposed well. |
| |
During
the first year of this Agreement, and only during the first year of this Agreement, and after the two initial test wells are
proposed, no Party may propose more than one well under this Agreement in any 90-day period, without the consent of 60% of
the working interest owners, unless (1) the additional well proposed is to test a separate geological objective from that
currently being tested (i.e. not the same source of supply) or (2) such additional well is proposed within six (6) months
of the expiration of the lease or (3) the Parties have agreed to an increase in the number of proposals that may be made.
Thereafter, proposals may be made under the terms of the Operating Agreement by the Parties. |
| |
|
| 8. |
Funding
Obligation - Well Costs: At least fifteen (15) days prior to the projected spud date of a well, each Party agrees to fund
its proportionate share of estimated dry hole costs, as reflected in any applicable approved AFE, to Operator or into a segregated
Operator account where such an account has been established, to assure payment to the drilling contractor. Failure to fund
within twenty (20) days following receipt of written notice of a funding deficiency shall constitute, at Operator’s
election, an election by Participant(s) not to participate in the well, and result in the penalties stated herein. |
| |
|
| |
A
Party shall likewise be obligated to advance payment for its share of estimated completion costs within forty eight (48) hours
of commencement of completion work on any well. Failure to fund within fifteen (15) days following receipt of written notice
of a funding deficiency for completion costs in which Participant(s) has elected to participate may, at Operator’s election,
be deemed to constitute a modification of the non-funding Party’s election, and such non- funding Party shall be deemed
to have elected non-consent with respect to the completion operation in the applicable well and the penalties of the Operating
Agreement shall apply. |
| |
|
| |
The
above funding provision shall apply to any wells drilled in the Project Area. |
| |
|
| |
The
drilling of each well in the Project Area shall be governed by the applicable operating agreement in the form attached hereto
as Exhibit C (the “Operating Agreement”). Where there is a conflict between the Operating Agreement and this Agreement,
this Agreement will control. |
| |
|
| 9. |
Net
Revenue Interest: Participant(s) shall acquire from Osage a delivered 78% net revenue interest in the leasehold interest leased
by Osage listed on Exhibit B. As to any leases acquired after the acquisition of 10,000 net acres, or closing of this Agreement,
which ever comes first, Participant(s) shall be delivered a net revenue of 78% unless the delivered net revenue received by
Osage is less than 78%, in which case the leasehold will be assigned to Participant at the same delivered net revenue received
by Osage. |
| 10. |
Leasehold:
At no administrative cost to Participant, Osage shall be responsible for acquiring the leases and shall be responsible for
assignment of Participant’s working interest to Participant(s) in said leases. Osage shall be responsible for maintenance
of lease records within the Project Area and shall timely remit rentals when due and comply with the other obligations of
the lease agreements on behalf of Participant(s). Participant(s) agrees to bear its proportionate share of any rental obligations
incurred by Osage in its behalf that accrue after closing. |
| |
|
| |
As
to any top leases included in the 10,000 net initial acres acquired, Osage shall bear all costs for exercising the purchase
option of said top leases, at the time they vest, and shall be responsible to pay the Participant(s) $650 per net acre for
any top leases that fail to vest. |
| |
|
| 11. |
Billings:
Except as otherwise provided herein, billings attributable to Participant’s interest in leases and operated wells shall
be billed and payable pursuant to the accounting provisions of the Operating Agreement. |
| |
|
| 12. |
AMI:
An Area of Mutual Interest (“AMI”) shall be established within the boundaries of the Project Area. “Leases”
means oil and gas leases, mineral interests, royalty interests, net profits interests, options or agreements to acquire or
earn the foregoing such as farmins, farmouts, participation agreements and similar agreements. The provisions of this paragraph
shall apply for a period of thirty (36) months from the date of this Agreement. Subject only to the specific terms of this
Agreement to the contrary, should a Party or any “Affiliate,” as that term is hereinafter defined, acquire an
interest in any Leases in the AMI, the acquiring Party shall offer the interest at a cost of leasehold bonus or purchase price
and directly attributable broker charges to other Parties in the Project Area proportionate to their Participation Interest
in the Project Area. Any Leases acquired hereunder, shall become subject to the terms of this Agreement. Should an acquired
interest lie both within and outside the AMI, for the purposes of the acquisition, the interest shall be deemed lying wholly
within the AMI. “Affiliate” means, with respect to either Party, any other person or entity directly or indirectly
controlling, controlled by, or under common control with, such Party. For purposes of this definition, the term “control”
(including the terms “controlled by” and “under common control with”) means the possession, directly
or indirectly, of the power to direct or cause the direction of the management and policies of any person or entity, whether
through the ownership of voting securities or by contract or otherwise. |
| 13. |
Term:
Except as otherwise provided herein, the term of this Agreement shall begin on the date hereof and continue f a period of
three (3) years, or as to a spacing or producing unit for a well, so long as the Operating Agreement remaii in effect. Notwithstanding
the foregoing, this agreement may be extended beyond the original term of 3 years working interest owners holding at least
75% of said working interest elect to extend the agreement which extensio shall be for a period of 1 year and for subsequent
periods of 1 year if so elected. |
| |
|
| 14. |
Notices:
All notices required hereunder shall be considered given when delivered personally or when sent by e-ma facsimile, or U.S.
Mail properly addressed as follows: |
| |
Slawson
Exploration Company, Inc. |
| |
727
North Waco, Suite 400 |
| |
Wichita,
KS 67203 |
| |
Attn:
Coni Stokes |
| |
Phone:
(316) 263-3201 Fax: (316) 268-0702 |
| |
E-mail:
cstokes @ slawsoncompanies.com |
| |
|
| |
Osage
Exploration and Development, Inc. 2445 5th Avenue, Suite 300 |
| |
San
Diego, CA 92131 Attn: Kim Bradford |
| |
Phone:
(619) 677-3956 |
| |
Fax:
(619) 677-3964 |
| |
E-mail:
kbradford@osageexploration.com |
| |
|
| |
U.S.
Energy Development Corporation |
| |
2350
North Forest Road |
| |
Getzville,
New York 14068 |
| |
Attn:
Douglas K. Walch |
| |
Phone:
716-636-0401 |
| |
Fax:
716-636-0418 |
| |
E-mail:
dwalch@usenergydevcorp.com |
Notwithstanding
the foregoing, notices or deliveries by U. S. Mail shall be deemed given or made only upon receipt by the addressee. Any Party
to this Agreement may change its mailing address, telephone number, facsimile number, or email address for notice hereunder effective
the thirtieth (30th) day after the giving of notice of such change in accordance with the provisions of this paragraph.
| 15. |
Nature
of Agreement: The liabilities of the Parties shall be several and not joint or collective, and each Party shall be responsible
only for its share of the costs and liabilities incurred as provided hereunder. It is not the purpose or intention of this
Agreement to create any partnership, mining partnership, joint venture, or any other association or entity, and neither this
Agreement nor the activities or operations hereunder shall be construed or considered as creating any such legal relationship.
Operator shall be responsible for marketing production from the wells drilled pursuant to this Agreement and shall account
to each participant for their proportionate share thereof. Each Party, however, shall have the right to market its production
in kind, but in doing so shall also assume the obligations of disbursing revenue to royalty and any other burden to its interest. |
| |
|
| 16. |
Miscellaneous
Provisions: |
| |
|
| |
Subject
to the other provisions of this Agreement, this Agreement and all provisions hereof shall inure to the benefit of and be binding
upon not only the Parties, but their respective heirs, successors, and assigns. The Parties may assign their rights, duties,
and obligations hereunder, so long as any assignment by a Party hereto is expressly made subject to the terms and conditions
herein contained. |
| |
i. |
Operator
shall have the right to require any Party who becomes an assignor to be the authorized agent for any of its assignees. |
| |
|
|
| |
ii. |
The
paragraph headings of this Agreement are inserted for convenience only and should not be considered a part of this Agreement
or used in its interpretation. |
| |
|
|
| |
iii. |
This
Agreement shall be governed by and construed in accordance with the laws of the State of Oklahoma. |
| |
|
|
| |
iv. |
The
provisions of this Agreement are intended to be severable. If any term or provision hereof is illegal or invalid for any reason
whatsoever, such illegality or invalidity shall not affect the legality or validity of the remainder of this Agreement. |
| |
|
|
| |
v. |
This
Agreement constitutes the entire understanding of the Parties in respect to the subject matter hereof, in lieu of any prior
agreement, and no amendment, modification, or alteration of the terms hereof shall be binding unless the same be in writing
and signed by the Party(ies) against whom/which it is sought to be enforced. |
| |
|
|
| |
vi. |
This
Agreement may be signed in counterparts, which, when taken together, shall have the effect of a single instrument. This Agreement,
however, shall not be binding on any Party unless and until a single original or counterparts, of this Agreement have been
signed by all Parties named therein. A printed faxed copy of a signature or a scanned and printed copy of a signature shall
be deemed to be the equivalent of an original. |
EXHIBIT
A to PARTICIPATION AGREEMENT
Summary
of Net Acres at Closing
| Sail | |
| 7,368.60 | |
| Lowry | |
| 689.71 | |
| GH | |
| 1,941.71 | |
| | |
| | |
| Totals | |
| 10,000.02 | |
Exhibit
31.1
Certification
of Principal Executive Officer
Pursuant
to Rule 13s-14(a) of
Securities
and Exchange Act of 1934
I,
Kim Bradford, certify that:
| 1. |
I
have reviewed this annual report on Form 10-K/A of Osage Exploration and Development, Inc.; |
| |
|
| 2. |
Based
on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect
to the period covered by this report; |
| |
|
| 3. |
Based
on my knowledge, the financial statements, and other financial information included in this report, fairly present in all
material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods
presented in this report; |
| |
|
| 4. |
The
registrant issuer’s other certifying officers and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15 (e) and 15d-15 (e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have: |
| |
|
| |
a) |
Designed
such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision,
to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in which this report is being prepared; |
| |
|
|
| |
b) |
Designed
such internal control over financial reporting, or caused such internal control over financial reporting to be designed under
our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles; |
| |
|
|
| |
c) |
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions
about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based
on such evaluation; and |
| |
|
|
| |
d) |
Disclosed
in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s
most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially
affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;
and |
| |
|
|
| 5. |
The
registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors
(or persons performing the equivalent functions): |
| |
|
| |
a) |
all
significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which
are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial
information; and |
| |
|
|
| |
b) |
any
fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s
internal control over financial reporting. |
Date:
September 24, 2014
| /s/
Kim Bradford |
|
| Kim Bradford |
|
| President and
Chief Executive Officer (Principal Executive Officer) |
|
Exhibit
31.2
Certification
of Principal Financial Officer
Pursuant
to Rule 13s-14(a) of
Securities
and Exchange Act of 1934
I,
Norman Dowling, certify that:
| 1. |
I
have reviewed this annual report on Form 10-K/A of Osage Exploration and Development, Inc.; |
| |
|
| 2. |
Based
on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect
to the period covered by this report; |
| |
|
| 3. |
Based
on my knowledge, the financial statements, and other financial information included in this report, fairly present in all
material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods
presented in this report; |
| |
|
| 4. |
The
registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15 (e) and 15d-15 (e)) and internal control over financial reporting (as
defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have: |
| |
|
| |
a) |
Designed
such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision,
to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in which this report is being prepared; |
| |
|
|
| |
b) |
Designed
such internal control over financial reporting, or caused such internal control over financial reporting to be designed under
our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles; |
| |
|
|
| |
c) |
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions
about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based
on such evaluation; and |
| |
|
|
| |
d) |
Disclosed
in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s
most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially
affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;
and |
| |
|
|
| 5. |
The
registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors
(or persons performing the equivalent functions): |
| |
|
| |
a) |
all
significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which
are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial
information; and |
| |
|
|
| |
b) |
any
fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s
internal control over financial reporting. |
| Date:
September 24, 2014 |
|
| |
|
| /s/
Norman Dowling |
|
| Norman Dowling |
|
| Chief Financial
Officer (Principal Financial Officer) |
|
Exhibit
32.1
CERTIFICATION
OF CHIEF EXECUTIVE OFFICER
PURSUANT
TO
18
U.S.C. SECTION 1350,
AS
ADOPTED PURSUANT TO
SECTION
906 OF THE SARBANES-OXLEY ACT OF 2002
The
undersigned hereby certifies, in accordance with 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002, in his or her capacity an officer of Osage Exploration and Development, Inc. (the “Company”), that, to his
or her knowledge, the Annual Report of the Company on Form 10-K/A for the period ended December 31, 2013 fully complies
with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 and that the information contained
in such report fairly presents, in all material respects, the financial condition and results of operation of the Company.
| Date:
September 24, 2014 |
|
| |
|
| |
/s/
Kim Bradford |
| |
Kim
Bradford, |
| |
President
and Chief Executive Officer, |
| |
(Principal
Executive Officer) |
Exhibit
32.2
CERTIFICATION
OF PRINCIPAL FINANCIAL OFFICER
PURSUANT
TO
18
U.S.C. SECTION 1350,
AS
ADOPTED PURSUANT TO
SECTION
906 OF THE SARBANES-OXLEY ACT OF 2002
The
undersigned hereby certifies, in accordance with 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002, in his or her capacity as an officer of Osage Exploration and Development, Inc. (the “Company”), that, to
his or her knowledge, the Annual Report of the Company on Form 10-K/A for the period ended December 31, 2013 fully complies
with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 and that the information contained
in such report fairly presents, in all material respects, the financial condition and results of operation of the Company.
| Date:
September 24, 2014 |
|
| |
|
| |
/s/
Norman Dowling |
| |
Norman
Dowling |
| |
Chief
Financial Officer |
| |
(Principal
Financial Officer) |
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