NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
March
31, 2014 and 2013 (unaudited)
1.
ORGANIZATION AND BASIS OF PRESENTATION
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
.
Osage
prepared the accompanying unaudited consolidated financial statements in accordance with accounting principles generally accepted
in the United States of America (“U.S. GAAP”) for interim financial information and pursuant to the rules and regulations
of the Securities and Exchange Commission (“SEC”) instructions to Form 10-Q and Item 310(b) of Regulation S-K. These
financial statements should be read together with the financial statements and notes in the Company’s 2013 Form 10-K filed
with the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with
U.S. GAAP were condensed or omitted. The accompanying financial statements reflect all adjustments and disclosures, which, in
the Company’s opinion, are necessary for fair presentation. All such adjustments are of a normal recurring nature. The results
of operations for the interim periods are not necessarily indicative of the results to be expected for the entire year.
2.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Going
Concern
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 5 - Debt). This raises 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. On April
5, 2013 we amended this agreement, increasing the facility to $20,000,000 and on April 7, 2014 we further amended this agreement,
increasing the facility to $30,000,000, extending the term of the facility by one year, reducing the interest rate from Libor
plus 15% to Libor plus 11% and agreeing to modify the covenants to reflect the transition from participant to operator.
The
Company and the lender are still in discussions about modifications to the covenants and the existing covenants, some of
which the Company is not in compliance with , remain in place until new covenants are agreed upon.
In
the quarter ended March 31, 2014, the Company raised approximately $6.4 million of gross proceeds in a private placement. (See
Note 10 - Equity)
.
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, (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.
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.
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 financial statements
and the reported amounts of revenues and expenses during the reporting period. Actual results could differ materially 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 relates to sales volumes. The significant estimates include the use of proved oil
and gas reserve estimates and the related present value of estimated future net revenues therefrom.
Reclassifications
Certain
amounts included in the prior period financial statements have been reclassified to conform to the current period’s presentation.
These reclassifications have no affect on the reported results in 2014 or 2013.
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.
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.
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 the three months ended March 31,
2014 and 2013. 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 the three months ended March 31, 2014 and three customers in prior year comparable quarter.
Deferred
Financing Costs
The
Company incurred deferred financing costs in connection with the Note Purchase Agreement (see Note 5), 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, which approximates the effective interest method.
Deferred
financing costs net of accumulated amortization at March 31, 2014 were $1,481,141. Amortization of deferred financing costs was
$347,983 and $314,462 for the three months ended March 31, 2014 and 2013, respectively.
Restricted
Cash
In
connection with the Apollo Note Purchase Agreement, as amended (see Note 5), the Company has classified $850,000, representing
three months interest, as restricted cash as of March 31, 2014 and December 31, 2013. The Company has also pledged $58,645 for
certain bonds and sureties. Restricted cash at March 31, 2014 was $908,629, compared to $908,645 at December 31, 2013.
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.
Net
Income/Loss Per Share
In
accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“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 three months ended March 31, 2014
and 2013:
|
|
Three Months Ended
March 31,
|
|
|
|
2014
|
|
|
2013
|
|
|
|
|
|
|
|
|
Net loss allocable to continuing operations
|
|
$
|
(935,127
|
)
|
|
$
|
(851,083
|
)
|
Net income allocable to discontinued operations
|
|
$
|
-
|
|
|
$
|
777,658
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted net income (loss) per share
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$
|
(0.02
|
)
|
|
$
|
(0.02
|
)
|
Discontinued operations
|
|
$
|
-
|
|
|
$
|
0.02
|
|
Basic and diluted weighted average shares outstanding
|
|
|
51,602,380
|
|
|
|
49,481,632
|
|
Potential
common shares consisted of 4,531,392 and 3,071,843 warrants to purchase common stock at March 31, 2014 and 2013, respectively.
All of these warrants were excluded from the computations for the three months ended March 31, 2014 and 2013, as their effect
would have been anti-dilutive.
Fair
Value of Financial Instruments
As
of March 31, 2014 and December 31, 2013, the fair value of cash and equivalents, accounts receivable, notes payable and accounts
payable and accrued expenses approximate carrying values because of the short-term maturity of these instruments.
FASB
ACS 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 use 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 March 31, 2014 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 March 31, 2014:
|
|
|
|
|
Total
|
|
|
Fair
Value Measurements Using:
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
|
Amount
|
|
|
Value
|
|
|
Inputs
|
|
|
Inputs
|
|
|
Inputs
|
|
March 31, 2014 assets (liabilities):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative liability
|
|
|
(425,625
|
)
|
|
|
(425,625
|
)
|
|
|
-
|
|
|
|
(425,625
|
)
|
|
|
-
|
|
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.
Recent
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.
3.
OIL AND GAS PROPERTIES
Oil
and gas properties consisted of the following:
|
|
March
31, 2014
|
|
|
December
31, 2013
|
|
Properties subject to amortization
|
|
$
|
29,653,820
|
|
|
$
|
25,551,336
|
|
Properties not subject to amortization
|
|
|
1,603,987
|
|
|
|
1,784,465
|
|
Capitalized asset retirement costs
|
|
|
3,698
|
|
|
|
3,659
|
|
Accumulated depreciation and depletion
|
|
|
(3,599,195
|
)
|
|
|
(2,606,243
|
)
|
Oil & gas properties, net
|
|
$
|
27,662,310
|
|
|
$
|
24,733,217
|
|
Depreciation
and depletion expense for oil and gas properties totaled $992,952 and $267,045 in the three months ended March 31, 2014 and 2013,
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 March 31, 2014, Osage operated approximately 5,457 net acres (11,228 gross) in thirty one sections, and remains joint-venture
partners with Slawson in approximately 4,192 net acres (26,167 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 March 31, 2014, the Company had 4,190 net acres
(5,085 gross) leased in Pawnee County. As of March 31, 2014, 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 Woodford
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 March 31, 2014, we had 4,253 net (9,509 gross) acres leased in Coal
County.
At
March 31, 2014 we have leased 18,092 net (51,989 gross) acres across three counties in Oklahoma as follows:
|
|
Gross
|
|
|
Osage
Net
|
|
Logan (non
operated)
|
|
|
26,167
|
|
|
|
4,192
|
|
Logan
|
|
|
11,228
|
|
|
|
5,457
|
|
Coal
|
|
|
9,509
|
|
|
|
4,253
|
|
Pawnee
|
|
|
5,085
|
|
|
|
4,190
|
|
|
|
|
51,989
|
|
|
|
18,092
|
|
4.
SEGMENT AND GEOGRAPHICAL INFORMATION
At
March 31, 2014, the Company’s continuing operations comprised one segment in one geographic region.
5.
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
11. This sale satisfied the requirements of the amendment and the Company is thus not obligated to issue additional Warrants to
Apollo.
During
the quarter ended March 31, 2014, we did not draw down any additional funds and, as of March 31, 2014, the amount outstanding
under the Note Purchase Agreement was $20,000,000. On April 3, 2014, the Company and Apollo amended the Note Purchase Agreement,
increasing the amount of the total facility to $30,000,000, extending the term by one year and reducing the interest rate from
Libor plus 15% to Libor plus 11%. The parties also agreed to modify future covenants to reflect the Company’s transition
from participant to operator.
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, which approximates the effective interest method, 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 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.
The Company and Apollo are negotiating
new covenants to the Note Purchase Agreement. Until these negotiations are complete existing covenants, some of which the Company
is not in compliance with , remain in place. Accordingly, the Company has classified borrowings under the Note Purchase
Agreement as short term in the accompanying consolidated balance sheets.
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, the Company recognized $1,210,560 of interest expense, of which $347,983 was non-cash
interest expense and $862,577 was cash interest expense. In connection with the Note Purchase Agreement and the Secured Promissory
Note, the Company recognized $766,505 of interest expense, of which $357,727 was non-cash interest expense, for the three month
ended March 31, 2013. Cash interest expense related to the Note Purchase Agreement and the Secured Promissory Note represented
$408,778 for the three months ended March 31, 2013.
6.
DERIVATIVE FINANCIAL INSTRUMENTS
The
Company entered into certain derivative financial instruments with respect to a portion of its oil and gas production in the third
quarter of 2013. Prior thereto, the Company had not entered into any derivative financial instruments. These instruments are used
to manage the inherent uncertainty of future revenues due to commodity price volatility and currently include only costless price
collars. The Company does not intend to hold or issue derivative financial instruments for speculative trading purposes and has
elected not to designate any of its derivative instruments for hedge accounting treatment.
As
of March 31, 2014, the Company had the following open oil derivative positions. These oil derivatives settle against the average
of the daily settlement prices for the WTI first traded contract month on the New York Mercantile Exchange (“NYMEX”)
for each successive day of the calculation period.
|
|
Price Collars
|
|
|
|
Monthly
|
|
|
Weighted Average
|
|
|
Weighted Average
|
|
|
|
Volume
|
|
|
Floor Price
|
|
|
Ceiling Price
|
|
Period
|
|
(BBLs/m)
|
|
|
($/BBL)
|
|
|
($/BBL)
|
|
Q2 - Q4, 2014
|
|
|
6,000
|
|
|
$
|
85.00
|
|
|
$
|
95.00
|
|
Q1 - Q2, 2015
|
|
|
6,000
|
|
|
$
|
80.00
|
|
|
$
|
93.50
|
|
As
of March 31, 2014, 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)
|
|
Q2 - 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 “Oil and gas derivatives’ caption in the accompanying consolidated statements of earnings.
The
following table sets forth the cash settlements and unrealized gains and losses on fair value changes for commodity derivatives
for the three months ended March 31, 2014.
|
|
Three Months Ended
|
|
|
|
March 31, 2014
|
|
Cash settlements to (by) Company
|
|
$
|
(47,669
|
)
|
Unrealized gains (losses) on commodity derivatives
|
|
|
(68,058
|
)
|
|
|
|
|
|
Loss on oil and gas derivatives
|
|
$
|
(115,727
|
)
|
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.
7.
COMMITMENTS AND CONTINGENCIES
Environment
Osage,
as owner and operator of oil and gas properties, 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 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 March 31,
2014, 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 and entered into a 36 month lease for a vehicle
at the termination of the original auto lease. In December 2013, the Company entered into a three year lease for office space
in Oklahoma City the term for which commenced in February 2014.
Rental
expense totaled $30,939 and $14,364 in the three months ended March 31, 2014 and 2013, respectively.
Future
minimum commitments under operating leases are as follows as of March 31, 2014:
Year
|
|
Amount
|
|
|
|
|
|
2014 (April - December)
|
|
$
|
137,825
|
|
2015
|
|
|
184,810
|
|
2016
|
|
|
186,098
|
|
2017
|
|
|
29,862
|
|
2018 and beyond
|
|
|
-
|
|
|
|
$
|
538,595
|
|
Capital
leases
The
Company entered into a lease for certain office furniture and equipment during the three months ended March 31, 2014. The term
of the lease is three years and as the lease essentially transfers the risks of ownership it is being accounted for as a capital
lease.
Leased
property under capital leases at March 31, 2014 includes:
|
|
March
31, 2014
|
|
Furniture and equipment
|
|
$
|
127,436
|
|
less: accumulated depreciation
|
|
|
(2,124
|
)
|
|
|
$
|
125,312
|
|
Total
depreciation expense under capital leases was $2,124 for the three months ended March 31, 2014 and as of that date the future
minimum lease payments under capital leases were as follows:
Year
|
|
Amount
|
|
|
|
|
|
2014 (April - December)
|
|
$
|
32,217
|
|
2015
|
|
|
42,956
|
|
2016
|
|
|
42,956
|
|
2017
|
|
|
7,158
|
|
|
|
|
125,287
|
|
Less amount representing interest
|
|
|
(1,354
|
)
|
Present value of minimum lease payments
|
|
$
|
123,933
|
|
|
|
|
|
|
Current maturities
|
|
$
|
42,195
|
|
Non-current maturities
|
|
|
81,738
|
|
|
|
$
|
123,933
|
|
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. We repaid the unsecured
Colombian term loan facility in October 2013 in conjunction with the sale of Cimarrona.
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.
8.
MAJOR CUSTOMERS
During
the three months ended March 31, 2014 and 2013, the Company had the following customers who accounted for all of its sales:
|
|
Three Months ended
|
|
|
Three Months ended
|
|
|
|
March 31, 2014
|
|
|
March 31, 2013
|
|
|
|
Amount
|
|
|
% of Total
|
|
|
Amount
|
|
|
% of Total
|
|
Slawson
|
|
$
|
1,917,664
|
|
|
|
72.7
|
%
|
|
$
|
952,071
|
|
|
|
78.6
|
%
|
Devon
|
|
|
543,469
|
|
|
|
20.6
|
%
|
|
|
177,922
|
|
|
|
14.7
|
%
|
Stephens
|
|
|
171,764
|
|
|
|
6.5
|
%
|
|
|
81,879
|
|
|
|
6.8
|
%
|
Sundance
|
|
|
4,518
|
|
|
|
0.2
|
%
|
|
|
-
|
|
|
|
0.0
|
%
|
Total
|
|
$
|
2,637,415
|
|
|
|
100.0
|
%
|
|
$
|
1,211,872
|
|
|
|
100.0
|
%
|
9.
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 petroleum 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 (“AROs”)
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 AROs. No income tax is applicable to the ARO as of March 31, 2014 and December 31, 2013, 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 for the three months ended March 31, 2014 is as follows:
|
|
Three Months Ended
|
|
|
|
March
31, 2014
|
|
Beginning balance
|
|
$
|
3,886
|
|
Incurred during the period
|
|
|
-
|
|
Reversed during the period
|
|
|
-
|
|
Additions for new wells
|
|
|
39
|
|
Accretion expense
|
|
|
200
|
|
Ending balance
|
|
$
|
4,125
|
|
10.
EQUITY
Common
Stock
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 $6.4 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.
As of March 31, 2014 units representing $6,396,000 had been sold, representing 7,106,672 shares of common stock and warrants to
purchase 2,842,662 shares of common stock. The placement agent fees related to these units as of March 31, 2014 were cash fees
of $319,880 and warrants to purchase 191,880 shares of common stock at $0.01 per share. In addition, the Company incurred legal
fees of $9,999 with respect to the private placement in the three months ended March 31, 2014.
On
January 2, 2014 we issued a total of 550,000 shares to three individuals in connection with amended employment and consulting
agreements. Stock based compensation had already been expensed for 150,000 shares as discussed below. The remaining 400,000 shares
vest on January 1, 2015, were valued at $436,000 based on closing prices of $1.00 for 200,000 shares and $1.18 for 200,000 shares
and are being expensed over one year.
During
the three months ended March 31, 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 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 150,000 shares were valued at $177,000, or $1.18 per
share, and were being expensed over the three years of the employment agreement. We recognized $14,750 of expense related to these
shares in the three months ended March 31, 2013. On January 2, 2014, we amended the employment agreement and the vesting of these
shares accelerated, and we recognized the unamortized portion of the stock based compensation expense in the fourth quarter of
2013.
Total
stock-based compensation expense was $109,000 and $378,750 for the three months ended March 31, 2014 and 2013, respectively.
Warrants
During
the three months ended March 31, 2014, 200,000 warrants were exercised by a consultant who had previously received the warrants
in exchange for services.
11.
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 is obligated to 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.
Raven has reimbursed the Company for the working capital adjustment. The Company and Raven are in discussions
about the status of the per barrel transportation rate with respect to the pipeline, and the Company does not presently have sufficient
information to estimate the outcome of these discussions.
The
following table sets forth the results of operations for the discontinued operations for the three months ended March 31, 2013:
|
|
March
31, 2013
|
|
Revenues
|
|
|
|
|
Oil revenues
|
|
$
|
615,687
|
|
Pipeline revenues
|
|
|
599,192
|
|
Total revenues
|
|
|
1,214,879
|
|
|
|
|
|
|
Operating costs and expenses
|
|
|
|
|
Operating expenses
|
|
|
316,538
|
|
Depreciation, depletion and accretion
|
|
|
58,752
|
|
Equity tax
|
|
|
32,964
|
|
General and administrative
|
|
|
21,790
|
|
Total operating costs and expenses
|
|
|
430,044
|
|
|
|
|
|
|
Operating income
|
|
|
784,835
|
|
|
|
|
|
|
Other income (expenses):
|
|
|
|
|
Interest income
|
|
|
71
|
|
Interest expense
|
|
|
(7,248
|
)
|
Income before income taxes
|
|
|
777,658
|
|
Provision for income taxes
|
|
|
-
|
|
|
|
|
|
|
Net income
|
|
$
|
777,658
|
|
12.
SUBSEQUENT EVENTS
As more fully discussed
in Note 5, the Company amended the Note Purchase Agreement with Apollo on April 3, 2014 and Apollo and the Company are in discussions
with respect to modifications covenants. On April 7, 2014, the Company drew down an additional $5 million, bringing total borrowings
under the note purchase agreement to $25 million.
Subsequent to March 31,
2014, the Company has raised additional proceeds of $150,000 in the private placement.