ITEM 1. FINANCIAL STATEMENTS
EnerJex Resources, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets
(Unaudited)
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2016
|
|
|
2015
|
|
Assets
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
1,253,377
|
|
|
$
|
3,101,682
|
|
Accounts receivable
|
|
|
1,005,876
|
|
|
|
977,488
|
|
Derivative receivable
|
|
|
150,005
|
|
|
|
2,531,401
|
|
Inventory
|
|
|
203,067
|
|
|
|
144,327
|
|
Marketable securities
|
|
|
210,990
|
|
|
|
210,990
|
|
Deposits and prepaid expenses
|
|
|
406,585
|
|
|
|
247,325
|
|
Total current assets
|
|
|
3,229,900
|
|
|
|
7,213,213
|
|
Non-current assets:
|
|
|
|
|
|
|
|
|
Fixed assets, net of accumulated depreciation of $1,728,361 and $1,658,073
|
|
|
2,001,294
|
|
|
|
1,995,010
|
|
Oil and gas properties using full-cost accounting, net of accumulated DD&A of $15,113,776 and $14,935,386
|
|
|
4,900,748
|
|
|
|
11,706,939
|
|
Other non-current assets
|
|
|
859,024
|
|
|
|
919,239
|
|
Total non-current assets
|
|
|
7,761,066
|
|
|
|
14,621,188
|
|
Total assets
|
|
$
|
10,990,966
|
|
|
$
|
21,834,401
|
|
Liabilities and Stockholders’ Deficit
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
314,086
|
|
|
$
|
1,142,842
|
|
Accrued liabilities
|
|
|
621,556
|
|
|
|
1,131,057
|
|
Current portion of long term debt
|
|
|
18,000,000
|
|
|
|
1,986,660
|
|
Total current liabilities
|
|
|
18,935,642
|
|
|
|
4,260,559
|
|
Asset retirement obligation
|
|
|
3,201,451
|
|
|
|
3,091,478
|
|
Long-term debt
|
|
|
-
|
|
|
|
16,625,000
|
|
Other long-term liabilities
|
|
|
1,661,481
|
|
|
|
390,937
|
|
Total non-current liabilities
|
|
|
4,862,932
|
|
|
|
20,107,415
|
|
Total liabilities
|
|
|
23,798,574
|
|
|
|
24,367,974
|
|
Commitments & Contingencies
|
|
|
|
|
|
|
|
|
Stockholders’ Deficit:
|
|
|
|
|
|
|
|
|
10% Series A Cumulative Perpetual Redeemable Preferred Stock, $0.001 par value, 25,000,000 shares authorized; 938,248 shares issued and outstanding June 30, 2016 and December 31, 2015
|
|
|
938
|
|
|
|
938
|
|
Series B Convertible Preferred stock, $0.001 par value, 1,764 shares authorized, issued and outstanding at June 30, 2016 and December 31, 2015
|
|
|
2
|
|
|
|
2
|
|
Common stock, $0.001 par value, 250,000,000 shares authorized; shares issued and outstanding 8,423,936 at June 30, 2016 and December 31, 2015
|
|
|
8,424
|
|
|
|
8,424
|
|
Paid-in capital
|
|
|
69,000,179
|
|
|
|
68,848,944
|
|
Accumulated deficit
|
|
|
(81,817,151
|
)
|
|
|
(71,391,881
|
)
|
Total stockholder’s deficit
|
|
|
(12,807,608
|
)
|
|
|
(2,533,573
|
)
|
Total liabilities and stockholders’ deficit
|
|
$
|
10,990,966
|
|
|
$
|
21,834,401
|
|
See Notes to Condensed Consolidated Financial
Statements (unaudited).
EnerJex Resources, Inc. and Subsidiaries
Condensed Consolidated Statements of Operations
(Unaudited)
|
|
For the Three Months Ended
|
|
|
For the Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenues
|
|
$
|
593,174
|
|
|
$
|
1,498,224
|
|
|
$
|
1,127,147
|
|
|
$
|
2,878,870
|
|
Natural gas revenues
|
|
|
2,506
|
|
|
|
87,258
|
|
|
|
24,532
|
|
|
|
204,453
|
|
Total revenues
|
|
|
595,680
|
|
|
|
1,585,482
|
|
|
|
1,151,679
|
|
|
|
3,083,323
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating costs
|
|
|
653,803
|
|
|
|
1,181,081
|
|
|
|
1,347,665
|
|
|
|
2,448,382
|
|
Depreciation, depletion and amortization
|
|
|
84,490
|
|
|
|
342,625
|
|
|
|
248,678
|
|
|
|
1,088,233
|
|
Impairment of oil and gas asset
|
|
|
2,137,663
|
|
|
|
11,421,613
|
|
|
|
6,644,596
|
|
|
|
27,822,989
|
|
Professional fees
|
|
|
59,308
|
|
|
|
97,094
|
|
|
|
137,117
|
|
|
|
350,823
|
|
Salaries
|
|
|
290,228
|
|
|
|
492,473
|
|
|
|
747,395
|
|
|
|
1,013,760
|
|
Administrative expense
|
|
|
127,820
|
|
|
|
199,294
|
|
|
|
311,526
|
|
|
|
430,033
|
|
Total expenses
|
|
|
3,353,312
|
|
|
|
13,734,180
|
|
|
|
9,436,977
|
|
|
|
33,154,220
|
|
Income (loss) from operations
|
|
|
(2,757,632
|
)
|
|
|
(12,148,698
|
)
|
|
|
(8,285,298
|
)
|
|
|
(30,070,897
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(332,456
|
)
|
|
|
(321,208
|
)
|
|
|
(662,219
|
)
|
|
|
(630,704
|
)
|
Loss on derivatives
|
|
|
(1,295,792
|
)
|
|
|
(1,958,127
|
)
|
|
|
(2,381,396
|
)
|
|
|
(2,175,649
|
)
|
Other income
|
|
|
922,942
|
|
|
|
1,116,686
|
|
|
|
2,174,186
|
|
|
|
2,211,343
|
|
Total other income (expense)
|
|
|
(705,306
|
)
|
|
|
(1,162,649
|
)
|
|
|
(869,429
|
)
|
|
|
(595,010
|
)
|
Net loss
|
|
$
|
(3,462,938
|
)
|
|
$
|
(13,311,347
|
)
|
|
$
|
(9,154,727
|
)
|
|
$
|
(30,665,907
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
loss
|
|
|
(3,462,938
|
)
|
|
|
(13,311,347
|
)
|
|
|
(9,154,727
|
)
|
|
|
(30,665,907
|
)
|
Preferred dividends
|
|
|
(684,139
|
)
|
|
|
(546,314
|
)
|
|
|
(1,270,543
|
)
|
|
|
(1,016,402
|
)
|
Net income (loss) attributable to common stockholders
|
|
$
|
(4,147,077
|
)
|
|
$
|
(13,857,661
|
)
|
|
$
|
(10,425,270
|
)
|
|
$
|
(31,682,309
|
)
|
Net income (loss) per share basic and diluted
|
|
$
|
(.49
|
)
|
|
$
|
(1.65
|
)
|
|
$
|
(1.24
|
)
|
|
$
|
(3.91
|
)
|
Weighted average shares
|
|
|
8,423,936
|
|
|
|
8,410,275
|
|
|
|
8,423,936
|
|
|
|
8,102,230
|
|
See Notes to Condensed Consolidated Financial
Statements (unaudited).
EnerJex Resources, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash
Flows
(Unaudited)
|
|
For the Six Months Ended
|
|
|
|
June 30,
|
|
|
|
2016
|
|
|
2015
|
|
Cash flows from operating activities
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(9,154,727
|
)
|
|
$
|
(30,665,907
|
)
|
Depreciation, depletion and amortization
|
|
|
248,678
|
|
|
|
1,088,233
|
|
Impairment of oil and gas assets
|
|
|
6,644,596
|
|
|
|
27,822,989
|
|
Stock, options and warrants issued for services
|
|
|
151,234
|
|
|
|
230,542
|
|
Accretion of asset retirement obligation
|
|
|
112,740
|
|
|
|
141,970
|
|
Settlement of asset retirement obligation
|
|
|
(2,768
|
)
|
|
|
(2,244
|
)
|
Loss on derivatives
|
|
|
2,381,396
|
|
|
|
2,171,320
|
|
Loss on sale of fixed assets
|
|
|
-
|
|
|
|
13,661
|
|
Adjustments to reconcile net income to cash from operating activities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(28,388
|
)
|
|
|
(698,288
|
)
|
Inventory
|
|
|
(58,740
|
)
|
|
|
61,397
|
|
Prepaid expenses
|
|
|
(159,260
|
)
|
|
|
499,642
|
|
Accounts payable
|
|
|
(828,756
|
)
|
|
|
(1,850,888
|
)
|
Accrued liabilities
|
|
|
(509,501
|
)
|
|
|
178,882
|
|
Cash flows used in operating
activities
|
|
|
(1,203,496
|
)
|
|
|
(1,008,691
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
(
Purchase) sale of fixed assets
|
|
|
(76,570
|
)
|
|
|
21,285
|
|
Additions to oil and gas properties
|
|
|
(16,794
|
)
|
|
|
(134,800
|
)
|
Proceeds from the sale of fixed assets
|
|
|
-
|
|
|
|
4,285
|
|
Cash flows used in investing activities
|
|
|
(93,364
|
)
|
|
|
(109,230
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
Repayments of long-term debt
|
|
|
(611,660
|
)
|
|
|
(2,061,660
|
)
|
Proceeds from borrowings
|
|
|
-
|
|
|
|
500,000
|
|
Proceeds from sale of preferred stock
|
|
|
-
|
|
|
|
4,683,071
|
|
Deferred financing costs
|
|
|
60,215
|
|
|
|
63,894
|
|
Dividends paid on preferred stock
|
|
|
-
|
|
|
|
(1,016,402
|
)
|
Cash flows (used in) provided by financing
activities
|
|
|
(551,445
|
)
|
|
|
2,168,903
|
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash
|
|
|
(1,848,305
|
)
|
|
|
1,050,982
|
|
Cash – beginning
|
|
|
3,101,682
|
|
|
|
805,524
|
|
Cash – ending
|
|
$
|
1,253,377
|
|
|
$
|
1,856,506
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosures:
|
|
|
|
|
|
|
|
|
Interest paid
|
|
$
|
448,041
|
|
|
$
|
384,130
|
|
Income taxes paid
|
|
$
|
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
Non-cash transactions:
|
|
|
|
|
|
|
|
|
Share based payments issued for services
|
|
$
|
151,234
|
|
|
$
|
230,542
|
|
See Notes to Condensed Consolidated Financial
Statements (unaudited).
EnerJex Resources, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial
Statements (unaudited)
Note 1 – Basis of Presentation
The unaudited condensed consolidated financial
statements of EnerJex Resources, Inc. (“we”, “us”, “our”, “EnerJex” and “Company”)
have been prepared in accordance with United States generally accepted accounting principles for interim financial information
and with the instructions to Form 10-Q and reflect all adjustments which, in the opinion of management, are necessary for a fair
presentation. All such adjustments are of a normal recurring nature. The results of operations for the interim
period are not necessarily indicative of the results to be expected for a full year. Certain amounts in the prior year
statements have been reclassified to conform to the current year presentations. The statements should be read in conjunction
with the financial statements and footnotes thereto included in our Annual Report Form 10-K for the fiscal year ended December
31, 2015.
Our consolidated financial statements include
the accounts of our wholly-owned subsidiaries, EnerJex Kansas, Inc., Black Sable Energy, LLC, Working Interest, LLC and Black Raven
Energy, Inc. for the three and six month periods ended June 30, 2016 and for the year ended December 31, 2015. All intercompany
transactions and accounts have been eliminated in consolidation.
Note 2 – Going Concern
The accompanying unaudited condensed consolidated
financial statements have been prepared assuming that the Company will continue as a going concern.
On October 3, 2011, the Company, entered
into an Amended and Restated Credit Agreement with Texas Capital Bank, and other financial institutions and banks
(“TCB” or “Bank”) that may become a party to the Credit Agreement from time to time. The facilities
provided under the Amended and Restated Credit Agreement was to be used to refinance a prior outstanding revolving loan
facility with TCB dated July 3, 2008, and for working capital and general corporate purposes. On August 15, 2014 the Company
entered into an Eighth Amendment to the Amended and Restated Credit Agreement. Among other things the Eighth Amendment
extended the maturity of the Agreement by three years to October 3, 2018. On August 12, 2015, the Company entered into a
Tenth Amendment to the Amended and Restated Credit Agreement. Among other things the Tenth Amendment established the
requirement of monthly borrowing base reductions commencing September 1, 2015 and continuing on the first of each month
thereafter. On November 13, 2015, the Company entered into a Eleventh Amendment to the Amended and Restated Credit Agreement.
The Eleventh Amendment reflects the following changes: (i) waived certain provisions of the Credit Agreement, (ii) suspend
certain hedging requirements, and (iii) to make certain other amendments to the Credit Agreement.
On April 1, 2016 the Company informed the Bank
that it would cease making the mandatory monthly borrowing base reduction payments and did not make the required April 1, 2016
payment. The Company made its mandatory quarterly interest payment on April 6, 2016 and on April 7, 2016 entered into a Forbearance
Agreement whereby the Bank agreed to not exercise remedies and rights afforded it under the Amended and Restated Credit Agreement
for thirty days. On May 31, 2016, the Company and the Bank amended to the Forbearance Agreement to extend the forbearance period
to August 31, 2016. On July 29, 2016, the Company and the Bank amended the Forbearance Agreement to extend the forbearance period
to October 1, 2016. The sixty day period will be used by the Company to pursue strategic alternatives.
The Company accesses a number of data bases
and utilizes several consultants to monthly prepare commodity price projections used in its cash forecasting models. The models
indicate it will have sufficient cash to satisfy obligation as they become due through the end of the first quarter of 2017, if
it ceases to make the principle reduction called for by the Tenth Amendment entered into by the Company on August 12, 2015. If
actual commodity prices are less than forecasted the Company would not have enough cash to meet obligations as they become due.
Should this occur the Company could suspend quarterly interest payments, restructure, amend or refinance existing debt through
private options or seek a protected reorganization under chapter 11 of the U.S. federal bankruptcy code.
As shown in the accompanying unaudited
condensed consolidated financial statements, the Company has incurred losses in 2015 and 2016, also generating negative cash
flows from operating activities. As of June 30, 2016, the Company had an accumulated deficit of $81,817,151 and a working
capital deficit (total current liabilities exceeded total current assets) of $15,705,742. The Company’s cash
balance and revenues generated are not currently sufficient and cannot be projected to cover operating expenses for the next
twelve months from the filing date of this report.
These factors raises substantial doubt about the Company’s
ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result
from the outcome of this uncertainty.
Note 3 – Stock Options
A summary of stock options
is as follows:
|
|
Options
|
|
|
Weighted
Avg.
Exercise
Price
|
|
|
Warrants
|
|
|
Weighted
Avg.
Exercise
Price
|
|
Outstanding December 31, 2015
|
|
|
288,331
|
|
|
$
|
10.17
|
|
|
|
1,904,286
|
|
|
$
|
2.75
|
|
Granted
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Cancelled
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Exercised
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Outstanding June 30, 2016
|
|
|
288,331
|
|
|
$
|
10.17
|
|
|
|
1,904,286
|
|
|
$
|
2.75
|
|
Note 4 – Fair Value Measurements
We hold certain financial assets which are required
to be measured at fair value on a recurring basis in accordance with the Statement of Financial Accounting Standard No. 157,
“Fair Value Measurements”
(“ASC Topic 820-10”). ASC Topic 820-10 establishes a fair value hierarchy
that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted
quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable
inputs (Level 3 measurements). ASC Topic 820-10 defines fair value as the price that would be received to sell an asset or
paid to transfer a liability in an orderly transaction between market participants on the measurement date. A fair value measurement
assumes that the transaction to sell the asset or transfer the liability occurs in the principal market for the asset or liability.
The three levels of the fair value hierarchy under ASC Topic 820-10 are described below:
Level 1. Valuations based on quoted prices
in active markets for identical assets or liabilities that an entity has the ability to access.
Level 2. Valuations based on quoted prices
for similar assets or liabilities, quoted prices for identical assets or liabilities in markets that are not active, or other inputs
that are observable or can be corroborated by observable data for substantially the full term of the assets or liabilities. We
consider the derivative liability to be Level 2. We determine the fair value of the derivative liability utilizing
various inputs, including NYMEX price quotations and contract terms.
Level 3. Valuations based on inputs that are
supported by little or no market activity and that are significant to the fair value of the assets or liabilities. We consider
our marketable securities to be Level 3
Our derivative instruments consist of fixed
price commodity swaps and deferred premium puts.
|
|
Fair Value Measurement
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
Crude oil contracts
|
|
$
|
-
|
|
|
$
|
150,005
|
|
|
$
|
-
|
|
Marketable Securities
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
210,990
|
|
Note 5 – Asset Retirement Obligation
Our asset retirement obligations relate to the
liabilities associated with the abandonment of oil and natural gas wells. The amounts recognized are based on numerous estimates
and assumptions, including future retirement costs, inflation rates and credit adjusted risk-free interest rates. The following
shows the changes in asset retirement obligations:
Asset retirement obligations, December 31, 2015
|
|
$
|
3,091,478
|
|
Liabilities settled during the period
|
|
|
(2,767
|
)
|
Accretion
|
|
|
112,740
|
|
Asset retirement obligations, June 30, 2016
|
|
$
|
3,201,451
|
|
Note 6 – Derivative Instruments
We have entered into certain derivative or physical
arrangements with respect to portions of our crude oil production to reduce our sensitivity to volatile commodity prices and/or
to meet hedging requirements under our Credit Facility. We believe that these derivative arrangements, although not free
of risk, allow us to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However,
derivative arrangements limit the benefit of increases in the prices of crude oil. Moreover, our derivative arrangements apply
only to a portion of our production.
We have an Inter-creditor Agreement in place
between us, our counterparties, BP Corporation North America, Inc. (“BP”) and our agent Texas Capital Bank, N.A., which allows Texas Capital Bank to also act as agent for the counterparties for the purpose
of holding and enforcing any liens or security interests resulting from our derivative arrangements. Therefore, we are not
required to post additional collateral, including cash.
The following derivative contract was in place
at June 30, 2016:
|
|
Term
|
|
Monthly Volumes
|
|
|
Price/Bbl
|
|
|
Fair Value
|
|
Deferred premium put
|
|
7/16-12/16
|
|
|
5,000 Bbls
|
|
|
$
|
60.00
|
|
|
|
150,005
|
|
Monthly volume is the weighted average throughout
the period.
The total fair value of the derivative
contract is shown as a derivative receivable in both the current and non-current sections of the balance sheet.
Note 7 – Long-Term Debt
Senior Secured Credit Facility
On October 3, 2011, the Company and DD Energy,
Inc., EnerJex Kansas, Inc., Black Sable Energy, LLC and Working Interest, LLC (“Borrowers”) entered into an Amended and
Restated Credit Agreement with Texas Capital Bank, N.A. (the “Bank”) and other financial institutions and banks that
may become a party to the Credit Agreement from time to time. The facilities provided under the Amended and Restated Credit Agreement
were used to refinance Borrowers’ prior outstanding revolving loan facility with Bank, dated July 3, 2008, and for working
capital and general corporate purposes.
At our option, loans under the facility will
bear stated interest based on the Base Rate plus Base Rate Margin, or Floating Rate plus Floating Rate Margin (as those terms are
defined in the Credit Agreement). The Base Rate will be, for any day, a fluctuating rate per annum equal to the higher of (a) the
Federal Funds Rate plus 0.50% and (b) the Bank’s prime rate. The Floating Rate shall mean, at Borrower’s option, a per annum interest
rate equal to (i) the Eurodollar Rate plus Eurodollar Margin, or (ii) the Base Rate plus Base Rate Margin (as those terms are defined
in the Amended and Restated Credit Agreement). Eurodollar borrowings may be for one, two, three, or nine months, as selected by
the Borrowers. The margins for all loans are based on a pricing grid ranging from 0.00% to 0.75% for the Base Rate Margin and 2.25%
to 3.00% for the Floating Rate Margin based on the Company’s Borrowing Base Utilization Percentage (as defined in the Amended and
Restated Credit Agreement).
On December 15, 2011, we entered into a First
Amendment to Amended and Restated Credit Agreement and Second Amended and Restated Promissory Note in the amount of $50,000,000
with the Bank. The Amendment reflected the addition of Rantoul Partners as an additional Borrower and added as additional security
for the loans the assets held by Rantoul Partners.
On August 31, 2012, we entered into a Second
Amendment to Amended and Restated Credit Agreement with the Bank. The Second Amendment: (i) increased our borrowing base to $7,000,000,
(ii) reduced the minimum interest rate to 3.75%, and (iii) added additional new leases as collateral for the loan.
On November 2, 2012, we entered into a Third
Amendment to Amended and Restated Credit Agreement with the Bank. The Third Amendment (i) increased our borrowing base to $12,150,000,
and (ii) clarified certain continuing covenants and provided a limited waiver of compliance with one of the covenants so clarified
for the quarter ended December 31, 2011.
On January 24, 2013, we entered into a Fourth
Amendment to Amended and Restated Credit Agreement, which was made effective as of December 31, 2012 with the Bank. The Fourth
Amendment reflects the following changes: (i) the Bank consented to the restructuring transactions related to the dissolution of
Rantoul Partners, and (ii) the Bank terminated a Limited Guaranty, as defined in the Credit Agreement, executed by Rantoul Partners
in favor of the Bank.
On April 16, 2013, the Bank increased our borrowing
base to $19.5 million.
On September 30, 2013, we entered into a Fifth
Amendment to the Amended and Restated Credit Agreement. The Fifth Amendment reflects the following changes: (i) an
expanded principal commitment amount of the Bank to $100,000,000, (ii) an increase in our Borrowing Base to $38,000,000, (iii)
the addition of Black Raven Energy, Inc. to the Credit Agreement as a borrower party, (iv) the addition of certain collateral and
security interests in favor of the Bank, and (v) the reduction of our current interest rate to 3.30%.
On November 19, 2013, we entered into a Sixth
Amendment to the Amended and Restated Credit Agreement. The Sixth Amendment reflects the following changes: (i) the addition of
Iberia Bank as a participant in our credit facility, and (ii) a technical correction to our covenant calculations.
On May 22, 2014, we entered into a Seventh Amendment
to the Amended and Restated Credit Agreement. The Seventh Amendment reflects the Bank’s consent to our issuance of up to
850,000 shares of our 10% Series A Cumulative Perpetual Preferred Stock.
On August 15, 2014, we entered into an Eighth
Amendment to the Amended and Restated Credit Agreement. The Eighth Amendment reflects the following changes: (i) the borrowing
base was increased from $38 million to $40 million, and (ii) the maturity of the facility was extended by three years to October
3, 2018.
On April 29, 2015, we entered into a Ninth Amendment
to the Amended and Restated Credit Agreement. In the Ninth Amendment, the Banks (i) re-determined the Borrowing Base based upon
the recent Reserve Report dated January 1, 2015, (ii) imposed affirmative obligations on the Company to use a portion of proceeds
received with regard to future sales of securities or certain assets to repay the loan, (iii) consented to non-compliance by the
Company with certain terms of the Credit Agreement, (iv) waived certain provisions of the Credit Agreement, and (v) agreed to certain
other amendments to the Credit Agreement.
On May 1, 2015, the Borrowers and the Banks
entered into a Letter Agreement to clarify that up to $1,000,000 in proceeds from any potential future securities offering will
be unencumbered by the Banks’ Liens as described in the Credit Agreement through November 1, 2015, and that, until November
1, 2015, such proceeds shall not be subject to certain provisions in the Credit Agreement prohibiting the Company from declaring
and paying dividends that may be due and payable to holders of securities issued in such potential offerings or issued prior to
the Letter Agreement.
On August 12, 2015, we entered into a Tenth
Amendment to the Amended and Restated Credit Agreement. The Tenth Amendment reflects the following changes: (i) allow the Company
to sell certain oil assets in Kansas, (ii) allow for approximately $1,300,000 of the proceeds from the sale to be reinvested in
Company owned oil and gas projects and (iii) apply not less than $1,500,000 from the proceed of the sale to outstanding loan balances.
On November 13, 2015, the Company entered into
a Eleventh Amendment to the Amended and Restated Credit Agreement. The Eleventh Amendment reflects the following changes: (i) waived
certain provisions of the Credit Agreement, (ii) suspend certain hedging requirements, and (iii) to make certain other amendments
to the Credit Agreement.
Our current borrowing base is $18,000,000, of
which we had borrowed $18,000,000 as of June 30, 2016. At June 30, 2016 and at December 31, 2015 the interest rate on amounts borrowed
under our credit facility was approximately 5.2% and 4.3% respectively. This facility expires on October 3, 2018.
On April 1, 2016 the Company informed the Bank
that it would cease making the mandatory monthly borrowing base reduction payments and did not make the required April 1, 2016
payment. The Company made its mandatory quarterly interest payment on April 6, 2016 and on April 7, 2016 entered into a Forbearance
Agreement whereby the Bank agreed to not exercise remedies and rights afforded it under the Amended and Restated Credit Agreement
for thirty days. On May 31, 2016, the Company and the Bank amended to the Forbearance Agreement to extend the forbearance period
to August 31, 2016.
Note 8 – Commitments & Contingencies
As of June 30, 2016 the Company had an outstanding
irrevocable letter of credit in the amount of $50,000 issued in favor of the Texas Railroad Commission. The letter of credit is
required by the Texas Railroad Commission for all companies operating in the state of Texas with production greater than limits
they prescribe.
Rent expense for the six months ended June 30,
2016 and 2015 was approximately $68,000 and $82,000 respectively. Future non-cancellable minimum lease payments are approximately
$70,000 for the remainder of 2016, $145,000 for 2017, $90,000 for 2018 and $77,000 for 2019.
Note 9 – Impairment of Oil and Gas
Properties
Pursuant to full cost accounting
rules, the Company must perform a ceiling test each quarter on its proved oil and natural gas assets within each separate
cost center. All of the Company’s costs are included in one cost center as all of the Company’s operations are
located in the United States. The Company’s ceiling test was calculated using trailing twelve-month, unweighted-average
first-day-of-the-month prices for oil and natural gas as of June 30, 2016, which were based on a West Texas Intermediate oil
price of $42.46 per Bbl and a Henry Hub natural gas price of $2.63 per Mcf (adjusted for basis and quality differentials),
respectively. This test resulted in a pre-tax write-down of $2,137,663 for the quarter ended June 30, 2016 and
$6,644,596 for the six month period ended June30, 2016. In 2015 the Company recorded pre –tax write-downs of
approximately $50.7 million. Additional material write-downs of the Company’s oil and gas properties could occur in
subsequent quarters in the event that oil and natural gas prices remain at current depressed levels, or if the Company
experiences significant downward adjustments to its estimated proved reserves.
Note 10 – Subsequent Events
On July 29, 2016, the Company and the Bank
amended the Forbearance Agreement to extend the forbearance period to October 1, 2016, upon the Company effecting a principal
reduction of $75,000.
The Company accesses a number of data bases
and utilizes several consultants to monthly prepare commodity price projections used in its cash forecasting models. The models
indicate it will have sufficient cash to satisfy obligation as they become due through the end of the first quarter of 2017, if
it ceases to make the principle reduction called for by the Tenth Amendment entered into by the Company on August 12, 2015. If
actual commodity prices are less than forecasted the Company would not have enough cash to meet obligations as they become due.
Should this occur the Company could suspend quarterly interest payments, restructure, amend or refinance existing debt through
private options or seek a protected reorganization under chapter 11 of the U.S. federal bankruptcy code.
We have reviewed
all material events through the date of this report in accordance with ASC 855-10.
FORWARD-LOOKING STATEMENTS
This report contains forward-looking statements.
These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All
statements, other than statements of historical fact, contained in this report, including statements regarding future events, our
future financial performance, business strategy and plans and objectives of management for future operations, are forward-looking
statements. We have attempted to identify forward-looking statements by terminology including “anticipates,” “believes,”
“can,” “continue,” “could,” “estimates,” “expects,” “intends,” “may,”
“plans,” “potential,” “predicts,” or “should” or the negative of these terms or other comparable
terminology. Although we do not make forward-looking statements unless we believe we have a reasonable basis for doing so, we cannot
guarantee their accuracy. These statements are only predictions and involve known and unknown risks, uncertainties and other factors,
including the risks outlined under “Risk Factors” or elsewhere in this report, which may cause our or our industry’s
actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity,
performance or achievements expressed or implied by these forward-looking statements. Moreover, we operate in a very competitive
and rapidly changing environment. New risks emerge from time to time and it is not possible for us to predict all risk factors,
nor can we address the impact of all factors on our business or the extent to which any factor, or combination of factors, may
cause our actual results to differ materially from those contained in any forward-looking statements. The factors impacting these
risks and uncertainties include, but are not limited to:
|
•
|
inability to attract and obtain additional development capital;
|
|
•
|
inability to achieve sufficient future sales levels or other operating results;
|
|
•
|
inability to efficiently manage our operations;
|
|
•
|
effect of our hedging strategies on our results of operations;
|
|
•
|
potential default under our secured obligations or material debt agreements;
|
|
•
|
estimated quantities and quality of oil reserves;
|
|
•
|
declining local, national and worldwide economic conditions;
|
|
•
|
fluctuations in the price of oil;
|
|
•
|
continued weather conditions that impact our abilities to efficiently manage our drilling and development activities;
|
|
•
|
the inability of management to effectively implement our strategies and business plans;
|
|
•
|
approval of certain parts of our operations by state regulators;
|
|
•
|
inability to hire or retain sufficient qualified operating field personnel;
|
|
•
|
increases in interest rates or our cost of borrowing;
|
|
•
|
deterioration in general or regional economic conditions;
|
|
•
|
adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect to existing operations;
|
|
•
|
the occurrence of natural disasters, unforeseen weather conditions, or other events or circumstances that could impact our operations or could impact the operations of companies or contractors we depend upon in our operations;
|
|
•
|
inability to acquire mineral leases at a favorable economic value that will allow us to expand our development efforts;
|
|
•
|
adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect to existing operations; and
|
|
•
|
changes in U.S. GAAP or in the legal, regulatory and legislative environments in the markets in which we operate.
|
You should not place undue reliance on any forward-looking
statement, each of which applies only as of the date of this report. Except as required by law, we undertake no obligation to update
or revise publicly any of the forward-looking statements after the date of this report to conform our statements to actual results
or changed expectations. For a detailed description of these and other factors that could cause actual results to differ materially
from those expressed in any forward-looking statement, please see “Risk Factors” in this document and in our Annual Report
on Form 10-K for the fiscal year ended December 31, 2015.
All references in this report to “we,”
“us,” “our,” “company” and “EnerJex” refer to EnerJex Resources, Inc. and our wholly-owned
operating subsidiaries, EnerJex Kansas, Inc., Black Sable Energy, LLC, Working Interest, LLC, and Black Raven Energy, Inc. unless
the context requires otherwise. We report our financial information on the basis of a December 31
st
fiscal year end.
AVAILABLE INFORMATION
We file annual, quarterly and other reports
and other information with the SEC. You can read these SEC filings and reports over the Internet at the SEC’s website
at www.sec.gov or on our website at
www.enerjex.com
. You can also obtain copies of the documents at prescribed
rates by writing to the Public Reference Section of the SEC at 100 F Street, NE, Washington, DC 20549 on official business days
between the hours of 10:00 am and 3:00 pm. Please call the SEC at (800) SEC-0330 for further information on the operations
of the public reference facilities. We will provide a copy of our annual report to security holders, including audited financial
statements, at no charge upon receipt to of a written request to us at EnerJex Resources, Inc., 4040 Broadway, Suite 508, San Antonio,
Texas 78209.
INDUSTRY AND MARKET DATA
The market data and certain other statistical
information used throughout this report are based on independent industry publications, government publications, reports by market
research firms or other published independent sources. In addition, some data are based on our good faith estimates.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
The following discussion of our financial
condition and results of operations should be read in conjunction with our financial statements and the related notes to our financial
statements included elsewhere in this report. In addition to historical financial information, the following discussion and analysis
contains forward-looking statements that involve risks, uncertainties and assumptions. Our actual results and timing of selected
events may differ materially from those anticipated in these forward-looking statements as a result of many factors, including
those discussed under ITEM 1A. Risk Factors and elsewhere in this report.
Overview
Our principal strategy is to acquire, develop,
explore and produce domestic onshore oil properties. Our business activities are currently focused in Kansas, Colorado, Nebraska
and Texas.
We continue to investigate multiple opportunities
to both unlock value and accelerate growth in an accretive manner on behalf of shareholders, including but not limited to mergers,
acquisitions, joint ventures, and non-dilutive financings. There can be no assurance of the results or timing associated with this
process.
We have substantially curtailed capital spending
in the current commodity price environment. Once the commodity market improves, we intend to focus our capital budget on the development
of our Colorado and Kansas properties where we have identified hundreds of drilling locations and reactivation or recompletion
opportunities that we believe will generate high rates of return with low risk profiles.
Recent Developments
The following is a brief description of our
most significant corporate developments that have occurred since the end of 2015:
On April 1, 2016 the Company informed the Bank
that it would cease making the mandatory monthly borrowing base reduction payments and did not make the required April 1, 2016
payment. The Company made its mandatory quarterly interest payments on April 6, 2016, and May 2, 2016. On April 7, 2016 the Company
entered into a Forbearance Agreement whereby the Bank agreed to not exercise remedies and rights afforded it under the Amended
and Restated Credit Agreement for thirty days. The thirty day period will be used by the Company to pursue strategic alternatives.
On April 28, 2016 the Bank informed the
Company that it would extend the above Forbearance Agreement period to May 31, 2016 upon effecting a principal reduction of $125,000.
In addition, the Company will receive an automatic extension to June 15, 2016 upon meeting certain terms and conditions specified
by the Bank. On May 31, 2016, the Company and the Bank amended to the Forbearance Agreement to extend the forbearance period to
August 31, 2016. On July 29, 2016, the Company and the Bank amended the Forbearance Agreement to extend the forbearance period
to October 1, 2016. The sixty day period will be used by the Company to pursue strategic alternatives.
The Company accesses a number of data bases
and utilizes several consultants to monthly prepare commodity price projections used in its cash forecasting models. The models
indicate it will have sufficient cash to satisfy obligation as they become due through the end of the first quarter of 2017, if
it ceases to make the mandatory principal reduction. If actual commodity prices are less than forecasted the Company would not
have enough cash to meet obligations as they become due. Should this occur the Company could suspend quarterly interest payments,
restructure, amend or refinance existing debt through private options or seek a protected reorganization under chapter 11 of the
U.S. federal bankruptcy code.
Net Production, Average Sales Price and Average Production
and Lifting Costs
The table below sets forth our net oil production
(net of all royalties, overriding royalties and production due to others), the average sales prices, average production costs and
direct lifting costs per unit of production for the three and six month periods ended June 30, 2016 and 2015.
|
|
For the Three Months Ended
|
|
|
For the Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
14,219
|
|
|
|
28,870
|
|
|
|
30,911
|
|
|
|
61,965
|
|
Natural gas (Mcf)
|
|
|
13,661
|
|
|
|
56,772
|
|
|
|
27,515
|
|
|
|
121,073
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
$
|
41.72
|
|
|
$
|
51.90
|
|
|
$
|
36.46
|
|
|
$
|
46.46
|
|
Natural gas (Mcf)
|
|
$
|
.18
|
|
|
$
|
1.54
|
|
|
$
|
.89
|
|
|
$
|
1.69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Production Cost
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per barrel of oil equivalent (“Boe”)
|
|
$
|
44.76
|
|
|
$
|
39.75
|
|
|
$
|
44.97
|
|
|
$
|
43.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Lifting Costs
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per Boe
|
|
$
|
39.64
|
|
|
$
|
30.81
|
|
|
$
|
37.97
|
|
|
$
|
29.81
|
|
|
(1)
|
Production costs include all operating expenses, transportation expenses, depreciation, depletion and amortization, lease operating expenses and all associated taxes. Impairment of oil properties is not included in production costs.
|
|
(2)
|
Direct lifting costs do not include impairment expense or depreciation, depletion and amortization.
|
Results of Operations for the Three and Six Months Ended June
30, 2016 and 2015 compared.
Income
:
|
|
Three Months Ended
|
|
|
Increase /
|
|
|
Six Months Ended
|
|
|
Increase /
|
|
|
|
June 30,
|
|
|
(Decrease)
|
|
|
June 30,
|
|
|
(Decrease)
|
|
|
|
2016
|
|
|
2015
|
|
|
$
|
|
|
2016
|
|
|
2015
|
|
|
$
|
|
Oil revenues
|
|
$
|
593,174
|
|
|
$
|
1,498,224
|
|
|
$
|
(905,050
|
)
|
|
$
|
1,127,147
|
|
|
$
|
2,878,870
|
|
|
$
|
(1,751,723
|
)
|
Natural gas revenues
|
|
|
2,506
|
|
|
|
87,258
|
|
|
|
(84,751
|
)
|
|
|
24,532
|
|
|
|
204,453
|
|
|
|
(179,921
|
)
|
Total
|
|
$
|
595,680
|
|
|
$
|
1,585,482
|
|
|
$
|
(989,801
|
)
|
|
$
|
1,151,679
|
|
|
$
|
3,083,323
|
|
|
$
|
(1,193,644
|
)
|
Oil Revenues
Oil revenues for the six months ended
June 30, 2016 were $1,127,147 compared to revenues of $2,878,870 for the six months ended June 30, 2015 and for the three
months ended June 30, 2016 were $593,174 compared to revenues of $1,498,224 for the same period in 2015. Of the year to date
revenue decrease of $1,751,723 approximately $619,000 was due to lower crude oil prices. Crude oil prices dropped $10.00 or
22% to an average price of $36.46 per barrel for the first six months of 2016 compared to $46.46 per barrel for the same
period in 2015. Additionally, revenues decreased approximately $1,132,000 due to lower production volumes. Oil production
decreased approximately 50% in the first six months of 2016 from 61,965 barrels produced in the half of 2015 to 30,911
barrels produced for the six months ended June 30, 2016. The production decrease was due primarily to the curtailment of both
growth and maintenance capital expenditures, and the sale of the Company’s Cherokee project in Eastern Kansas.
Natural Gas Revenues
Natural
gas revenues for the six months ended June 30, 2016 was $24,532 compared to revenues of $204,453 for the six months ended June
30, 2015
and for the three months ended June
30, 2016 were $2,507 compared to revenues of $87,258 for the same period in 2015. Of the year to date revenue decrease of $179,921
approximately $96,500 was due to lower natural gas prices. Natural gas prices dropped $.80 or 44% from an average price of $1.69
per mcf for the first six months of 2015 to an average price of $.89 per mcf for the same period of 2016. Additionally, revenues
decreased approximately $83,400 due to lower production volumes. Production decreased in the first six months of 2016 from 121,073
mcf to 27,515 mcf for the comparable period of 2015. The production decrease was due primarily to the curtailment of both growth
and maintenance capital expenditures.
Expenses:
|
|
Three Months Ended
|
|
|
Increase /
|
|
|
Six Months Ended
|
|
|
Increase /
|
|
|
|
June 30,
|
|
|
(Decrease)
|
|
|
June 30,
|
|
|
(Decrease)
|
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
|
|
Production expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating costs
|
|
$
|
653,803
|
|
|
$
|
1,181,080
|
|
|
$
|
(527,277
|
)
|
|
$
|
1,347,665
|
|
|
$
|
2,448,382
|
|
|
$
|
(1,100,717
|
)
|
Depreciation, depletion and amortization
|
|
|
84,490
|
|
|
|
342,625
|
|
|
|
(258,135
|
)
|
|
|
248,678
|
|
|
|
1,088,233
|
|
|
|
(839,556
|
)
|
Impairment of oil & gas properties
|
|
|
2,137,663
|
|
|
|
11,421,613
|
|
|
|
(9,283,950
|
)
|
|
|
6,644,596
|
|
|
|
27,822,989
|
|
|
|
(21,178,393
|
)
|
Total production expenses
|
|
|
2,875,956
|
|
|
|
12,945,318
|
|
|
|
(10,069,362
|
)
|
|
|
8,240,939
|
|
|
|
31,359,603
|
|
|
|
(23,118,666
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Professional fees
|
|
|
59,308
|
|
|
|
97,094
|
|
|
|
(37,784
|
)
|
|
|
137,117
|
|
|
|
350,823
|
|
|
|
(213,706
|
)
|
Salaries
|
|
|
290,228
|
|
|
|
492,473
|
|
|
|
(202,245
|
)
|
|
|
747,395
|
|
|
|
1,013,760
|
|
|
|
(266,365
|
)
|
Administrative expense
|
|
|
127,820
|
|
|
|
199,294
|
|
|
|
(71,474
|
)
|
|
|
311,526
|
|
|
|
430,033
|
|
|
|
(118,507
|
)
|
Total general expenses
|
|
|
477,356
|
|
|
|
788,861
|
|
|
|
(311,505
|
)
|
|
|
1,196,038
|
|
|
|
1,794,616
|
|
|
|
(598,578
|
)
|
Total production and general expenses
|
|
|
3,353,312
|
|
|
|
13,734,179
|
|
|
|
(10,380,867
|
)
|
|
|
9,436,977
|
|
|
|
33,154,219
|
|
|
|
(23,717,242
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss)
from operations
|
|
|
(2,757,632
|
)
|
|
|
(12,148,698
|
)
|
|
|
(9,391,066
|
)
|
|
|
(8,285,298
|
)
|
|
|
(30,070,897
|
)
|
|
|
(21,785,601
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(332,456
|
)
|
|
|
(321,208
|
)
|
|
|
11,248
|
|
|
|
(662,219
|
)
|
|
|
(630,704
|
)
|
|
|
31,515
|
|
Loss on derivatives
|
|
|
(1,295,792
|
)
|
|
|
(1,958,127
|
)
|
|
|
(662,335
|
)
|
|
|
(2,381,396
|
)
|
|
|
(2,175,649
|
)
|
|
|
205,747
|
|
Other income
|
|
|
922,942
|
|
|
|
1,116,686
|
|
|
|
193,744
|
|
|
|
2,174,186
|
|
|
|
2,211,343
|
|
|
|
37,157
|
|
Total other income (expense)
|
|
|
(705,306
|
)
|
|
|
(1,162,649
|
)
|
|
|
(457,343
|
)
|
|
|
(869,429
|
)
|
|
|
(595,010
|
)
|
|
|
274,419
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss)
|
|
$
|
(3,462,938
|
)
|
|
$
|
(13,311,347
|
)
|
|
$
|
9,848,409
|
|
|
$
|
(9,154,727
|
)
|
|
$
|
(30,665,907
|
)
|
|
$
|
21,511,180
|
|
Direct Operating Costs
Direct
operating costs include direct labor and equipment costs related to pumping, gauging, pulling, well repairs, compression, transportation
costs, and general maintenance requirements in our oil and gas fields. These costs also include certain contract labor costs,
and other non-capitalized expenses. Direct operating costs for the six months ended June 30, 2016 decreased $1,100,717, or 45%
to $1,347,665 from $2,448,382 for the six months ended June 30, 2015
and
for the three months ended June 30, 2016 were $653,803 compared to $1,181,080 for the same period in 2015. Year to date direct
operating costs per boe increased $8.16 or approximately 27% in 2016 compared to 2015 at $37.97 per boe and $29.81 per boe respectively.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization
for the six months ended June 30, 2016 was $248,678 compared to $1,088,233
for
the six months ended June 30, 2015
and for the
three months ended June 30, 2016 was $84,490 compared to $342,625 for the same period in 2015. The year to date decrease in depletion
expense of approximately $840,000 or approximately 77% was due to lower per boe depletion rates in 2016 compared to 2015, as well
as lower overall production in 2016. The lower depletion rate is the result of a write-down of oil and gas properties mandated
by the Securities and Exchange Commission’s Full Cost Ceiling Test rules (see footnote 9 to the financial statements for
a full explanation of the Ceiling Test). Depletion expense per boe decreased $6.57 or approximately 57% in the first half of 2016
compared to the first half of 2015 and as also discussed above production decreased approximately 57% six months over six month
due primarily to lower spending on lease operating expenditures and lower investments in maintenance capital.
Impairment of Oil and Gas Properties
Under the full cost method of accounting, capitalized
oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the sum
of the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves and the cost of unproved
properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved
properties that are not subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized.
For
the six months ended June 30, 2016, we recognized an impairment expense on our evaluated oil and gas properties of $6,644,596. For the six months ended June 30, 2015, we recognized an impairment expense on our evaluated oil and gas properties
of $27,822,989. For the three months ended June 30, 2016 and 2015, we recognized an impairment expense on our evaluated oil
and gas properties of $2,137,663 and $11,421,613, respectively.
Professional Fees
Professional
fees for the six months ended June 30, 2016 were $137,117 compared to $350,823 for the six months ended June 30, 2015
and
$59,308 for the three months ended June 30, 2016 compared to $97,094 for the same period in 2015. The decrease in year to
date professional fees of approximately $214,000 was due primarily to reduced spending in 2016 on investor relations
services, third party reserve engineering fees and legal expenditures incurred with outside attorneys. These decreases
were partially offset by increased audit fees.
Salaries
Salaries
for the six months ended June 30, 2016 were $747,395 compared to $1,013,760 for the six months ended June 30, 2015
and
$290,228 for the three months ended June 30, 2016 compared to $492,473 for the same period in 2015. The decrease in year to date
salaries of approximately $266,000 is due primarily to reduced number of employees.
Administrative Expenses
Administrative
expenses for the six months ended June 30, 2016 were $311,526 compared to $430,033 for the six months ended June 30, 2015
and $127,820 for the three months ended June 30, 2016
compared to $199,294 for the same period in 2015. The year to date decrease of approximately $119,000 in 2016 was due primarily
lower insurance premiums, SEC costs, meals travel & entertainment, rents bank fees and office supplies. The decrease were
partially offset by higher IT, telecommunications and software costs and lower G&A expense reimbursements from a working interest
partner.
Interest Expense
Interest
expense for the six months ended June 30, 2016 was $662,219 compared to $630,704 for the six months ended June 30, 2015 an increase
of approximately $32,000
and $332,456 for the
three months ended June 30, 2016 compared to $321,208 for the same period in 2015. Year to date interest expense increased as
a result of higher interest rates but was partially offset by decreased outstanding borrowings in 2016 compared to 2015.
Loss on Derivatives
We
recorded an unrealized loss of $2,381,396 in the marking to market of our derivative contracts for the first six months of 2016
compared to an unrealized loss of $2,175,649 for the six months ended June 30, 2015
and
$1,295,792 for the three months ended June 30, 2016 compared to $1,958,127 for the same period in 2015. The year to date loss
in 2016 was due primarily to increases in spot prices in 2016 compared to smaller increases in the spot prices in 2015.
Other Income
Other
income decreased $37,157 in 2016 from $2,211,343 in 2015 to $2,174,186 in 2016
and
$922,942 for the three months ended June 30, 2016 compared to $1,116,686 for the same period in 2015. The year to date decrease
was due to the realization of gains associated with our derivative contracts in line with the prior period of 2015.
Net Loss
The
net loss for the six months ended June 30, 2016 was $9,154,727 compared to a net loss of $30,665,907 for the six months ended
June 30, 2015
and $3,462,938 for the three months
ended June 30, 2016 compared to $13,311,347 for the same period in 2015. The year to date decrease in the net loss
was due primarily to the reduction in the impairment of oil and gas properties of $21.17 million.
Liquidity and Capital Resources
Liquidity is a measure of a company’s ability
to meet potential cash requirements. We have historically met our capital requirements through debt financing, revenues from operations,
asset sales, and the issuance of equity securities. Due to the decline in oil prices, the resulting decline in our reserves as
reflected in our reserve report which caused a corresponding reduction in our borrowing base, and the recent issuances of equity
securities from our “shelf” registration, it will be more difficult in 2016 to use our historical means of meeting our
capital requirements to provide us with adequate liquidity to fund our operations and capital program.
The following table summarizes total current
assets, total current liabilities and working capital.
|
|
June 30,
2016
|
|
|
December 31,
2015
|
|
|
Increase /
(Decrease)
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets
|
|
$
|
3,229,900
|
|
|
$
|
7,213,213
|
|
|
$
|
(3,983,313
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities
|
|
$
|
18,935,642
|
|
|
$
|
4,260,559
|
|
|
$
|
(14,675,083
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working Capital
|
|
$
|
(15,705,742
|
)
|
|
$
|
2,952,654
|
|
|
$
|
(18,658,396
|
)
|
Senior Secured Credit Facility
On October 3, 2011, the Company and DD Energy,
Inc., EnerJex Kansas, Inc., Black Sable Energy, LLC and Working Interest, LLC (“Borrowers”) entered into an Amended and
Restated Credit Agreement with Texas Capital Bank, N.A. (the “Bank”) and other financial institutions and banks that
may become a party to the Credit Agreement from time to time. The facilities provided under the Amended and Restated Credit Agreement
were used to refinance Borrowers prior outstanding revolving loan facility with Bank, dated July 3, 2008, and for working capital
and general corporate purposes.
At our option, loans under the facility will
bear stated interest based on the Base Rate plus Base Rate Margin, or Floating Rate plus Floating Rate Margin (as those terms are
defined in the Credit Agreement). The Base Rate will be, for any day, a fluctuating rate per annum equal to the higher of (a) the
Federal Funds Rate plus 0.50% and (b) the Bank’s prime rate. The Floating Rate shall mean, at Borrower’s option, a per annum interest
rate equal to (i) the Eurodollar Rate plus Eurodollar Margin, or (ii) the Base Rate plus Base Rate Margin (as those terms are defined
in the Amended and Restated Credit Agreement). Eurodollar borrowings may be for one, two, three, or nine months, as selected by
the Borrowers. The margins for all loans are based on a pricing grid ranging from 0.00% to 0.75% for the Base Rate Margin and 2.25%
to 3.00% for the Floating Rate Margin based on the Company’s Borrowing Base Utilization Percentage (as defined in the Amended and
Restated Credit Agreement).
On December 15, 2011, we entered into a First
Amendment to Amended and Restated Credit Agreement and Second Amended and Restated Promissory Note in the amount of $50,000,000
with the Bank, which closed on December 15, 2011. The Amendment reflected the addition of Rantoul Partners as an additional Borrower
and added as additional security for the loans the assets held by Rantoul Partners.
On August 31, 2012, we entered into a Second
Amendment to Amended and Restated Credit Agreement with the Bank. The Second Amendment: (i) increased our borrowing base to $7,000,000,
(ii) reduced the minimum interest rate to 3.75%, and (iii) added additional new leases as collateral for the loan.
On November 2, 2012, we entered into a Third
Amendment to Amended and Restated Credit Agreement with the Bank. The Third Amendment (i) increased our borrowing base to $12,150,000,
and (ii) clarified certain continuing covenants and provided a limited waiver of compliance with one of the covenants so clarified
for the quarter ended December 31, 2011.
On January 24, 2013, we entered into a Fourth
Amendment to Amended and Restated Credit Agreement, which was made effective as of December 31, 2012 with the Bank. The Fourth
Amendment reflects the following changes: (i) the Bank consented to the restructuring transactions related to the dissolution of
Rantoul Partners, and (ii) the Bank terminated a Limited Guaranty, as defined in the Credit Agreement, executed by Rantoul Partners
in favor of the Bank.
On April 16, 2013, the Bank increased our borrowing
base to $19.5 million.
On September 30, 2013, we entered into a Fifth
Amendment to the Amended and Restated Credit Agreement. The Fifth Amendment reflects the following changes: (i) an expanded
principal commitment amount of the Bank to $100,000,000, (ii) an increase in our Borrowing Base to $38,000,000, (iii) the addition
of Black Raven Energy, Inc. to the Credit Agreement as a borrower party, (iv) the addition of certain collateral and security interests
in favor of the Bank, and (v) the reduction of our current interest rate to 3.30%.
On November 19, 2013, we entered into a Sixth
Amendment to the Amended and Restated Credit Agreement. The Sixth Amendment reflects the following changes: (i) the addition of
Iberia Bank as a participant into our credit facility, and (ii) made a technical correction to our covenant calculations.
On May 22, 2014, we entered into a Seventh Amendment
to the Amended and Restated Credit Agreement. The Seventh Amendment reflects the Bank’s consent to our issuance of up to
850,000 shares of our 10% Series A Cumulative Perpetual Preferred Stock.
On August 15, 2014, we entered into an Eighth
Amendment to the Amended and Restated Credit Agreement. The Eighth Amendment reflects the following changes: (i) the borrowing
base was increased from $38 million to $40 million, and (ii) the maturity of the facility was extended by three years to October
3, 2018.
On April 29, 2015, we entered into a Ninth Amendment
to Amended and Restated Credit Agreement. In the Ninth Amendment, the Banks (i) re-determined the Borrowing Base based upon the
recent Reserve Report dated January 1, 2015, (ii) imposed affirmative obligations on the Company to use a portion of proceeds received
with regard to future sales of securities or certain assets to repay the loan, (iii) consented to non-compliance by the Company
with certain terms of the Credit Agreement, (iv) waived certain provisions of the Credit Agreement, and (v) agreed to certain other
amendments to the Credit Agreement.
On May 1, 2015, the Borrowers and the Banks
entered into a Letter Agreement to clarify that up to $1,000,000 in proceeds from any potential future securities offering will
be unencumbered by the Banks’ Liens as described in the Credit Agreement through November 1, 2015, and that, until November
1, 2015, such proceeds shall not be subject to certain provisions in the Credit Agreement prohibiting the Company from declaring
and paying dividends that may be due and payable to holders of securities issued in such potential offerings or issued prior to
the Letter Agreement.
On August 12, 2015, we entered into a Tenth
Amendment to the Amended and Restated Credit Agreement. The Tenth Amendment reflects the following changes: (i) allow the Company
to sell certain oil assets in Kansas, (ii) allow for approximately $1,300,000 of the proceeds from the sale to be reinvested in
Company owned oil and gas projects and (iii) apply not less than $1,500,000 from the proceed of the sale to outstanding loan balances.
On November 13, 2015, the Company entered into
a Eleventh Amendment to the Amended and Restated Credit Agreement. The Eleventh Amendment reflects the following changes: (i) waived
certain provisions of the Credit Agreement, (ii) suspend certain hedging requirements, and (iii) to make certain other amendments
to the Credit Agreement.
Our current borrowing base is $18,000,000,
of which we had borrowed $18,000,000 as of June 30, 2016. At June 30, 2016 and at December 31, 2015 the interest rate on amounts
borrowed under our credit facility was approximately 5.2% and 4.3% respectively. This facility expires on October 3, 2018.
Satisfaction of our cash obligations
for the next 12 months
We intend to meet our near term cash obligations
through the monetization of derivative contracts, assets sales and cash flow generated from operations. Due to the declines in
oil prices, the resulting decline in our reserves caused a corresponding reduction to our borrowing base, and recent issuances
of equity securities from our “shelf” registration, it will be more difficult in 2016 to use our historical means to
meet our cash obligations in the next twelve months.
Summary of product research and development
We do not anticipate performing any significant
product research and development under our plan of operation.
Expected purchase or sale of any significant
equipment
We anticipate that we will purchase the necessary
production and field service equipment required to produce oil during our normal course of operations over the next twelve months.
Significant changes in the number of employees
At December 31, 2015 and at June 30, 2016 we
had 16 full-time employees, including field personnel. As production and drilling activities increase or decrease, we may have
to continue to adjust our technical, operational and administrative personnel as appropriate. We are using and will continue to
use independent consultants and contractors to perform various professional services, particularly in the area of land services,
reservoir engineering, geology drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance,
permitting and environmental assessment. We believe that this use of third-party service providers may enhance our ability to contain
operating and general expenses, and capital costs.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements
that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition,
revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
Critical Accounting Policies and Estimates
Our critical accounting estimates include the
value of our oil and gas properties, asset retirement obligations, and share-based payments.
Oil and Gas Properties
We follow the full-cost method of accounting
under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize
internal costs that can be directly identified with our acquisition, exploration and development activities and do not include
costs related to production, general corporate overhead or similar activities.
Proved properties are amortized using the units
of production (UOP) method. Currently we only have operations in the Unites States of America. The UOP calculation multiplies the
percentage of estimated proved reserves produced each quarter by the cost of these reserves. The amortization base in the UOP calculation
includes the sum of proved property, net of accumulated depreciation, depletion and amortization (DD&A), estimated future development
costs (future costs to access and develop proved reserves) and asset retirement costs, less related salvage value.
The cost of unproved properties are excluded
from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until
development projects are placed into service. Geological and geophysical costs not associated with specific properties are recorded
as proved property immediately. Unproved properties are reviewed for impairment quarterly.
Under the full cost method of accounting, the
net book value of oil and gas properties, less deferred income taxes, may not exceed a calculated “ceiling.” The ceiling
limitation is (a) the present value of future net revenues computed by applying current prices of oil & gas reserves (with
consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved
oil & gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current
costs) to be incurred in developing and producing the proved reserves computed using a discount factor of 10 percent and assuming
continuation of existing economic conditions plus (b) the cost of properties not being amortized plus (c) the lower of cost or
estimated fair value of unproven properties included in the costs being amortized less (d) income tax effects related to differences
between book and tax basis of properties. Future cash outflows associated with settling accrued retirement obligations are excluded
from the calculation. Estimated future cash flows are calculated using end-of-period costs and an unweighted arithmetic average
of commodity prices in effect on the first day of each of the previous 12 months held flat for the life of the production, except
where prices are defined by contractual arrangements.
Any excess of the net book value of proved
oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional
DD&A in the statement of operations. The ceiling calculation is performed quarterly. For the six months ended June 30, 2016,
we incurred a $6,644,596 impairment charge and for the six months ended June 30, 2015 our impairment charge was $27,822,989. For
the year ended December 31, 2014, there were no impairments resulting from the quarterly ceiling tests.
Proceeds from the sale or disposition of oil
and gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25%) of our
reserve quantities are sold, in which case a gain or loss is recognized in income.
Asset Retirement Obligations
The asset retirement obligation relates to the
plugging and abandonment costs when our wells are no longer useful. We determine the value of the liability by obtaining quotes
for this service and estimate the increase we will face in the future. We then discount the future value based on an intrinsic
interest rate that is appropriate for us. If costs rise more than what we have expected there could be additional charges in the
future however we monitor the costs of the abandoned wells and we will adjust this liability if necessary.
Share-Based Payments
The value we assign to the options and warrants
that we issue is based on the fair market value as calculated by the Black-Scholes pricing model. To perform a calculation of the
value of our options and warrants, we determine an estimate of the volatility of our stock. We need to estimate volatility
because there has not been enough trading of our stock to determine an appropriate measure of volatility. We believe our estimate
of volatility is reasonable, and we review the assumptions used to determine this whenever we issue new equity instruments. If
we have a material error in our estimate of the volatility of our stock, our expenses could be understated or overstated.
Effects of Inflation and Pricing
The oil industry is very cyclical and the demand
for goods and services of oil field companies, suppliers and others associated with the industry puts extreme pressure on the economic
stability and pricing structure within the industry. Material changes in prices impact revenue stream, estimates of future reserves,
borrowing base calculations of bank loans and value of properties in purchase and sale transactions. Material changes in prices
can impact the value of oil companies and their ability to raise capital, borrow money and retain personnel. We anticipate business
costs and the demand for services related to production and exploration will fluctuate while the commodity prices for oil remains
volatile.