UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


Washington, D.C.
 20549





FORM
10-Q





[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934





For the quarterly
period ended September 30, 2016





[
] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934





For the transition
period from                
            to





Commission
File Number: 001-32989








Yuma Energy, Inc.


(Exact name of registrant as specified in its charter)





CALIFORNIA
(State or other jurisdiction of incorporation)



94-0787340
(IRS Employer Identification No.)





1177 West Loop South, Suite 1825
Houston, Texas
(Address of principal executive offices)



77027
(Zip Code)





(713) 968-7000
(Registrant’s telephone number, including area
code)





N/A
(Former name, former address and former fiscal year, if changed
since last report)





Indicate by check
mark whether the registrant (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days. Yes
[X] No [ ]





Indicate by check
mark whether the registrant has submitted electronically and posted
on its corporate Web site, if any, every Interactive Data File
required to be submitted and posted pursuant to Rule 405 of
Regulation S-T (§232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant was
required to submit and post such files). Yes [X] No [
]





Indicate by check
mark whether the registrant is a large accelerated file, an
accelerated file, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated
file,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange
Act.





Larger accelerated
filer [
]                                                                                     
Accelerated filer [ ]





Non-accelerated
filer [ ](Do not check if a smaller reporting
company)             
Smaller reporting company [X]





Indicate by check
mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes [ ] No [X]





At October 25,
2016, 3,775,636 shares of the registrant’s common stock, no
par value, were outstanding.














Explanatory
Note





On
February 10, 2016, Yuma Energy, Inc., a California corporation (the
“Company”), Yuma
Energy, Inc., a Delaware corporation and wholly owned subsidiary of
the Company (“Yuma
Delaware”), Yuma Merger Subsidiary, Inc., a Delaware
corporation and wholly owned subsidiary of Yuma Delaware
(“Merger
Subsidiary”), and Davis Petroleum Acquisition Corp.
(“Davis”)
entered into an agreement and plan of merger and reorganization, as
subsequently amended on September 2, 2016 (the “Merger Agreement”), providing for
the merger of the Company with and into Yuma Delaware (the
“Reincorporation
Merger”) and the merger of Merger Subsidiary with and
into Davis (the “Merger”). The Reincorporation
Merger and the Merger were consummated on October 26, 2016. In
connection with the Reincorporation Merger, the Company converted
each outstanding share of its 9.25% Series A Cumulative Redeemable
Preferred Stock, no par value per share (the “Series A Preferred Stock”), into
35 shares of its common stock, no par value per share (the
“Common Stock”),
and then each outstanding share of Common Stock was exchanged for
one-twentieth of one share of common stock, $0.001 par value per
share, of Yuma Delaware (the “Yuma Delaware Common Stock”). In
connection with the Merger, Yuma Delaware issued approximately
7,455,000 shares of Yuma Delaware Common Stock to former holders of
common stock of Davis and approximately 1,754,000 shares of Series
D Convertible Preferred Stock, $0.001 par value per share (the
“Series D Preferred
Stock”), of Yuma Delaware, to former holders of Davis
preferred stock. After the Reincorporation Merger and the Merger,
Yuma Delaware had approximately 12,201,000 shares of Yuma Delaware
Common Stock issued and outstanding.





This
Quarterly Report on Form 10-Q of the Company for the period ended
September 30, 2016, is being filed by its successor company, Yuma
Delaware. The financial information in this Quarterly Report and
the accompanying management’s discussion and analysis reflect
the corporate status of the reporting entity as it was at September
30, 2016.

















TABLE OF CONTENTS








PART
I – FINANCIAL INFORMATIONItem
1.
Financial
Statements.Consolidated
Balance Sheets as of September 30, 2016 and December 31,
2015.
4Consolidated
Statements of Operations for the Three and Nine Months ended
September 30, 2016 and 2015.
6Consolidated
Statements of Comprehensive Income (Loss) for the Three and Nine
Months ended September 30, 2016 and 2015.
7Consolidated
Statements of Changes in Equity for the Nine Months ended September
30, 2016 and the year ended December 31, 2015.
8Consolidated
Statements of Cash Flows for the Nine Months ended September 30,
2016 and 2015.
9Unaudited
Condensed Notes to the Consolidated Financial
Statements.
10Item
2.
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations.
25Item
3.
Quantitative
and Qualitative Disclosures About Market Risk.
36Item
4.
Controls
and Procedures.
36PART II – OTHER INFORMATIONItem
1.
Legal
Proceedings.
37Item
1A.
Risk
Factors.
37Item
2.
Unregistered
Sales of Equity Securities and Use of Proceeds.
38Item
3.
Defaults
Upon Senior Securities.
38Item
4.
Mine
Safety Disclosures.
38Item
5.
Other
Information.
38Item
6.
Exhibits.
39Signatures.
40

















PART I. FINANCIAL INFORMATION


Item 1. Financial Statements.


Yuma
Energy, Inc.


CONSOLIDATED
BALANCE SHEETS





September
30,
December
31,2016
2015(Unaudited)
(As
Restated)ASSETSCURRENT
ASSETS:Cash and cash
equivalents
$1,831,928
$5,355,191Accounts
receivable, net of allowance for doubtful accounts:Trade
2,942,948
2,829,266Officers and
employees
65,153
75,404Other
338,461
633,573Commodity
derivative instruments
1,016,583
2,658,047Prepayments
321,237
704,523Other deferred
charges
29,921
415,740Total current
assets
6,546,231
12,671,744OIL AND GAS
PROPERTIES (full cost method):Not subject to
amortization
15,336,916
14,288,716Subject to
amortization
205,331,835
204,512,038220,668,751
218,800,754Less: accumulated
depreciation, depletion and amortization
(134,312,088)
(117,304,945)Net oil and gas
properties
86,356,663
101,495,809OTHER PROPERTY AND
EQUIPMENT:Land, buildings and
improvements
2,795,000
2,795,000Other property and
equipment
3,497,948
3,460,5076,292,948
6,255,507Less: accumulated
depreciation and amortization
(2,361,010)
(2,174,316)Net other property
and equipment
3,931,938
4,081,191OTHER ASSETS AND
DEFERRED CHARGES:Commodity
derivative instruments
177,724
1,070,541Deposits
414,064
264,064Other noncurrent
assets
-
38,104Total other assets
and deferred charges
591,788
1,372,709TOTAL
ASSETS
$97,426,620
$119,621,453





The
accompanying notes are an integral part of these financial
statements.





4





Yuma
Energy, Inc.


CONSOLIDATED
BALANCE SHEETS – CONTINUED





September
30,
December
31,2016
2015(Unaudited)
(As
Restated)LIABILITIES AND
EQUITYCURRENT
LIABILITIES:Current maturities
of debt
$29,800,000
$30,063,635Accounts payable,
principally trade
6,378,942
7,933,664Commodity
derivative instruments
74,331
-Asset retirement
obligations
243,711
70,000Other accrued
liabilities
2,593,813
1,781,484Total current
liabilities
39,090,797
39,848,783OTHER NONCURRENT
LIABILITIES:Asset retirement
obligations
8,571,895
8,720,498Commodity
derivative instruments
4,432
-Deferred
taxes
144,700
1,417,364Other
liabilities
7,467
30,090Total other
noncurrent liabilities
8,728,494
10,167,952EQUITY:Preferred
stock
10,828,603
10,828,603Common stock, no
par value (300 million shares authorized, 3,628,991 and 3,591,731
issued)
142,724,775
141,858,946Accumulated
earnings (deficit)
(103,946,049)
(83,082,831)Total
equity
49,607,329
69,604,718TOTAL LIABILITIES
AND EQUITY
$97,426,620
$119,621,453








The
accompanying notes are an integral part of these financial
statements.





5





Yuma
Energy, Inc.


CONSOLIDATED
STATEMENTS OF OPERATIONS


(Unaudited)





Three Months
Ended
September
30,
Nine Months
Ended
September
30,2016
2015
2016
2015(As
Restated)

(As
Restated)REVENUES:Sales of natural
gas and crude oil
$3,151,626
$4,649,009
$9,207,636
$14,756,582Net gains (losses)
from commodity derivatives
447,936
3,893,650
(407,828)
3,267,239Total
revenues
3,599,562
8,542,659
8,799,808
18,023,821EXPENSES:Lease
operating
1,798,868
2,718,919
5,692,077
9,168,260Re-engineering and
workovers
132,708
1,136
132,708
555,628Marketing cost of
sales
-
234,507
-
434,189General and
administrative – stock-based compensation
189,211
338,619
909,309
2,210,950General and
administrative – other
1,581,619
1,873,484
5,742,824
5,389,859Depreciation,
depletion and amortization
1,711,043
3,123,812
6,178,248
11,020,278Asset retirement
obligation accretion expense
107,760
170,209
318,016
499,766Impairments
-
-
11,015,589
4,927,508Other
6,612
(274,329)
(10,173)
444,320Total
expenses
5,527,821
8,186,357
29,978,598
34,650,758INCOME (LOSS) FROM
OPERATIONS
(1,928,259)
356,302
(21,178,790)
(16,626,937)OTHER INCOME
(EXPENSE):Interest
expense
(245,359)
(131,114)
(974,403)
(337,499)Other,
net
10,745
14,055
17,311
35,521Total
other income (expense)
(234,614)
(117,059)
(957,092)
(301,978)NET INCOME (LOSS)
BEFORE INCOME TAXES
(2,162,873)
239,243
(22,135,882)
(16,928,915)Income tax expense
(benefit)
(47,429)
329,653
(1,272,664)
(3,605,839)NET INCOME
(LOSS)
(2,115,444)
(90,410)
(20,863,218)
(13,323,076)PREFERRED STOCK,
PERPETUAL PREFERRED SERIES A:Dividends paid in
cash
-
320,626
-
940,315Dividends in
arrears
320,625
-
961,877
-NET INCOME (LOSS)
ATTRIBUTABLE TO COMMONSTOCKHOLDERS
$(2,436,069)
$(411,036)
$(21,825,095)
$(14,263,391)EARNINGS (LOSS) PER
COMMON SHARE ADJUSTED FOROCTOBER
26,2016 1-FOR-20 REVERSE STOCK SPLIT:Basic
$(0.67)
$(0.11)
$(6.04)
$(4.03)Diluted
$(0.67)
$(0.11)
$(6.04)
$(4.03)WEIGHTED AVERAGE
NUMBER OF COMMON SHARESOUTSTANDING
ADJUSTED FOR OCTOBER 26, 2016 1-FOR-20REVERSE
STOCK SPLIT:Basic
3,628,683
3,580,163
3,611,241
3,539,755Diluted
3,628,683
3,580,163
3,611,241
3,539,755


The
accompanying notes are an integral part of these financial
statements.





6





Yuma
Energy, Inc.


CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)


(Unaudited)





Three Months
Ended
September
30,
Nine Months
Ended
September
30,2016
2015
2016
2015(As
Restated)

(As
Restated)NET
LOSS
$(2,115,444)
$(90,410)
$(20,863,218)
$(13,323,076)OTHER COMPREHENSIVE
INCOME (LOSS):Commodity
derivatives sold
-
-
-
(119,917)Less income
taxes
-
-
-
(46,168)Commodity
derivatives sold, net of income taxes
-
-
-
(73,749)Reclassification of
loss on settledcommodity
derivatives
-
9,971
-
41,525Less income
taxes
-
3,839
-
15,987Reclassification of
loss on settledcommodity
derivatives, net of income taxes
-
6,132
-
25,538OTHER COMPREHENSIVE
INCOME (LOSS)
-
6,132
-
(48,211)COMPREHENSIVE
LOSS
$(2,115,444)
$(84,278)
$(20,863,218)
$(13,371,287)





The
accompanying notes are an integral part of these financial
statements.








7





Yuma
Energy, Inc.


CONSOLIDATED
STATEMENTS OF CHANGES IN EQUITY





September
30,
December
31,2016
2015(Unaudited)
(As
Restated)PERPETUAL PREFERRED
STOCK - 9.25% CUMULATIVE AND REDEEMABLE, NO PAR VALUE:Balance at
beginning of period: 554,596 for 2016 and 507,739 shares for
2015
$10,828,603
$9,958,217Sales of 46,857
shares for 2015
-
870,386Balance at end of
period: 554,596 shares for both 2016 and 2015
10,828,603
10,828,603COMMON STOCK, NO
PAR VALUE:Balance at
beginning of period: 3,591,731 shares for 2016 and 3,456,993 shares
for 2015
141,858,946
137,469,772Sales of 67,373
shares of common stock in 2015
-
1,363,160Restricted stock
awards, of which 51,929 vested in 2016 and 83,806 vested in
2015
725,573
3,171,477Buy back shares
from vested stock awards: 14,669 in 2016 and 16,441 in
2015
(74,422)
(300,732)Stock appreciation
rights issued in 2015, of which 39,456 vested in 2016
214,678
155,269Balance at end of
period: 3,628,991 shares for 2016 and 3,591,731 shares for
2015
142,724,775
141,858,946ACCUMULATED OTHER
COMPREHENSIVE INCOME:Balance at
beginning of period
-
38,801Comprehensive loss
from commodity derivative instruments, net of income
taxes
-
(38,801)Balance at end of
period
-
-ACCUMULATED
EARNINGS (DEFICIT):Balance at
beginning of period
(83,082,831)
(67,195,800)Net
loss
(20,863,218)
(14,839,840)Series A perpetual
preferred stock cash dividends
-
(1,047,191)Balance at end of
period
(103,946,049)
(83,082,831)TOTAL
EQUITY
$49,607,329
$69,604,718





The
accompanying notes are an integral part of these financial
statements.


8


Yuma Energy, Inc.





CONSOLIDATED
STATEMENTS OF CASH FLOWS


(Unaudited)





Nine Months
Ended
September
30,2016
2015(As
Restated)CASH FLOWS FROM
OPERATING ACTIVITIES:Reconciliation of
net loss to net cash provided by (used in) operating
activitiesNet
loss
$(20,863,218)
$(13,323,076)Impairment of oil
and gas properties
11,015,589
-Impairment of
goodwill
-
4,927,508Depreciation,
depletion and amortization of property and equipment
6,178,248
11,020,278Accretion of asset
retirement obligation
318,016
499,766Stock-based
compensation net of capitalized cost
909,309
2,210,950Amortization of
other assets and liabilities
518,478
209,904Deferred tax
expense (benefit)
(1,272,664)
(3,608,239)Bad debt expense
increase (decrease)
(10,173)
787,264Unrealized losses
on commodity derivatives
2,613,044
1,847,371Other
-
(342,944)Changes in current
operating assets and liabilities:Accounts
receivable
201,854
4,411,640Other
current assets
383,286
(77,453)Accounts
payable
(1,471,397)
(13,938,649)Other
current liabilities
783,551
1,095,356Other noncurrent
assets and liabilities
(108,618)
-NET CASH USED IN
OPERATING ACTIVITIES
(804,695)
(4,280,324)CASH FLOWS FROM
INVESTING ACTIVITIES:Capital
expenditures on property and equipment
(2,588,455)
(11,211,634)Proceeds from sale
of property
340,603
30,442Decrease in
short-term investments
-
1,170,868NET CASH USED IN
INVESTING ACTIVITIES
(2,247,852)
(10,010,324)(CASH FLOWS FROM
FINANCING ACTIVITIES:Change in borrowing
on line of credit
-
$6,800,000Proceeds from
insurance note
-
813,562Payments on
insurance note
(263,635)
(579,005)Line of credit
financing costs
(132,659)
(215,141)Net proceeds from
sale of common stock
-
1,363,160Net proceeds from
sale of perpetual preferred stock
-
870,386Cash dividends to
preferred shareholders
-
(940,315)Common stock
purchased from employees
(74,422)
(300,732)Other
-
(31,485)NET CASH PROVIDED
BY (USED IN) FINANCING ACTIVITIES
(470,716)
7,780,430NET DECREASE IN
CASH AND CASH EQUIVALENTS
(3,523,263)
(6,510,218)CASH AND CASH
EQUIVALENTS AT BEGINNING OF PERIOD
5,355,191
11,558,322CASH AND CASH
EQUIVALENTS AT END OF PERIOD
$1,831,928
$5,048,104Supplemental
disclosure of cash flow information:Interest payments
(net of interest capitalized)
$354,344
$73,342Interest
capitalized
$395,244
$750,107Supplemental
disclosure of significant non-cash activity:(Increase) decrease
in capital expenditures financed by accounts payable
$83,325
$2,979,301





The
accompanying notes are an integral part of these financial
statements.


9








Yuma
Energy, Inc.


UNAUDITED
CONDENSED NOTES TO THE CONSOLIDATED FINANCIAL
STATEMENTS





NOTE 1 – BASIS OF PRESENTATION





These
consolidated financial statements are unaudited; however, in the
opinion of management, they reflect all adjustments necessary for a
fair presentation of the results for the periods reported. All such
adjustments are of a normal recurring nature unless disclosed
otherwise. The notes to the consolidated financial statements have
been condensed and do not include all of the information and
disclosures required by accounting principles generally accepted in
the United States of America (“GAAP”) for complete
financial statements. These consolidated financial statements
should be read in conjunction with the consolidated financial
statements as of and for the year ended December 31, 2015 and the
notes thereto included with the Annual Report on Form 10-K/A of
Yuma Energy, Inc., a California corporation (the
“Company”) filed with the Securities and Exchange
Commission (“SEC”) on May 23, 2016.





On
October 26, 2016, the shareholders of the Company approved, among
other proposals, (i) the conversion (the “Series A
Conversion”) of the 9.25% Series A Cumulative Redeemable
Preferred Stock, no par value per share of the Company (the
“Series A Preferred Stock”), into common stock, no par
value per share of the Company (the “common stock”), at
a rate of 35 shares of common stock for each share of Series A
Preferred Stock; (ii) the reincorporation of the Company from
California to Delaware pursuant to a merger (the
“Reincorporation Merger”) of the Company with and into
Yuma Energy, Inc., a Delaware corporation and wholly owned
subsidiary of the Company (“Yuma Delaware”); and (iii)
the merger (the “Merger”) of Yuma Merger Subsidiary,
Inc., a Delaware corporation and wholly owned subsidiary of Yuma
Delaware (“Merger Subsidiary”), with and into Davis
Petroleum Acquisition Corp., a Delaware corporation
(“Davis”) with Davis surviving as a wholly owned
subsidiary of Yuma Delaware. The Company issued approximately
19,411,000 shares of common stock as a result of the Series A
Conversion. Immediately following the Series A Conversion, each
share of common stock was exchanged for one-twentieth of one share
of common stock, $0.001 par value per share of Yuma Delaware (the
“Yuma Delaware Common Stock”) as part of the
Reincorporation Merger. The shares outstanding presented in this
quarterly report on Form 10-Q have been retroactively adjusted to
account for the 1-for-20 reverse stock split. See Note 15 –
Subsequent Events, for a discussion of the Reincorporation Merger
and the Merger.





Restatement Background





On May
11, 2016, the Company determined that there were non-cash errors in
the computation of its income tax provision and the recording of
its deferred taxes related to its asset retirement obligations, its
stock based compensation, its allocation of the purchase price in
the Pyramid merger and resultant amount of goodwill, the tax
amortization of that goodwill, the tax treatment of expenses
related to the Pyramid merger, the incorrect roll forward of the
historic net operating losses and the difference in the book and
tax basis in its properties. As a result, the Company’s
computation of its income tax provision and the net amount of its
deferred tax liability were restated for the years ended December
31, 2015, 2014 and 2013 and the applicable quarterly periods in
2015 and 2014.





As a
result, management, the Audit Committee and the Board of Directors
determined after consideration of the relevant facts and
circumstances, that the Company’s consolidated financial
statements as of December 31, 2015 and 2014, and for the years
ended December 31, 2015, 2014 and 2013 contained within the
Company’s Annual Report on Form 10-K for the year ended
December 31, 2015 (the “2015 Form 10-K”), and the
financial data included in its interim consolidated financial
statements set forth in its quarterly reports on Form 10-Q for the
quarter ended September 30, 2014, and for all subsequent quarters
through the quarter ended December 31, 2015, should be restated,
and that such financial statements previously filed with the SEC,
should no longer be relied upon.


10








As a
result, on May 23, 2016, the Company filed Amendment No. 1 to its
Annual Report on Form 10-K for the year ended December 31, 2015
(the “Amended Filing”). Prior period financial
information in this Form 10-Q has been amended where necessary to
reflect the restatement. Additional information regarding the
restatement is contained in the Amended Filing. Therefore, this
Form 10-Q should be read in conjunction with the Amended
Filing.





NOTE 2 – LIQUIDITY CONSIDERATIONS





The
Company has borrowings which require, among other things,
compliance with certain financial ratios. Due to operating losses
the Company has sustained during recent quarters as a result of the
prolonged weak commodity price environment and other factors, the
Company was not in compliance with the trailing four quarter funded
debt to EBITDA financial ratio covenant under its credit facility
at September 30, 2015, December 31, 2015, March 31, 2016, June 30,
2016 and September 30, 2016, its current ratio as of June 30, 2016
and September 30, 2016, as well as its EBITDA to interest expense
ratio as of December 31, 2015, March 31, 2016, June 30, 2016 and
September 30, 2016. In addition, the Company was not in compliance
due to its going concern opinion at March 31, 2016 and June 30,
2016, as well as its failure to maintain a certain financial bank
as its principal depository bank. On May 20, 2016, the Company
remedied its compliance with regard to the depository bank. On
December 30, 2015, the Company’s wholly owned subsidiary,
Yuma Exploration and Production Company, Inc.
(“Exploration”) entered into the Waiver, Borrowing Base
Redetermination and Ninth Amendment (the “Ninth
Amendment”) to the credit agreement which provided for a
$29.8 million conforming borrowing base, with an automatic
reduction to $20.0 million on May 31, 2016, and waived the
compliance with the trailing four quarter funded debt to EBITDA and
EBITDA to interest expense financial ratio covenants or any other
events of default under the credit facility for the quarters ended
September 30, 2015 and December 31, 2015. On June 6, 2016 and
effective as of May 31, 2016, Exploration entered into the Waiver
and Tenth Amendment to the credit agreement as amended by the
Waiver and Amendment to the Waiver and Tenth Amendment dated August
25, 2016 (the “Tenth Amendment”), which maintained the
borrowing base at $29.8 million and automatically reduced the
borrowing base to $20.0 million on the earliest of (i) September
23, 2016, if the registration statement on Form S-4 (the
“Form S-4”) filed with the SEC pursuant to the pending
Merger Agreement had not been declared effective by such date; (ii)
the date that was forty-seven days after the date the Form S-4 had
been declared effective by the SEC; (iii) October 31, 2016; and
(iv) in the event of the termination of the merger agreement. As of
September 30, 2016, the Company had a working capital deficit of
$32.5 million inclusive of the Company’s outstanding debt
under its credit facility, which was fully drawn with no additional
borrowing capacity available.


Upon
the closing of the Merger discussed in Note 15 – Subsequent
Events, the outstanding balance under the credit facility was
assumed by Yuma Delaware in a new credit facility. Under the new
credit facility, which was entered into in connection with the
Merger, Yuma Delaware is in compliance with the credit facility.
This new credit facility supersedes the Company’s previous
credit agreement and non-compliance matters discussed
above.


NOTE
3 – ACCOUNTING STANDARDS


Not Yet Adopted


In
October 2016, the Financial Accounting Standards Board
(“FASB”) issued ASU 2016-16, “Income Taxes (Topic
740): Intra-Entity Transfers of Assets Other Than Inventory,”
which requires an entity to recognize the income tax consequences
of an intra-entity transfer of an asset other than inventory when
the transfer occurs and eliminates the exception for an
intra-entity transfer of an asset other than inventory. This ASU is
effective for annual and interim periods beginning in 2018 and is
required to be adopted using a modified retrospective approach,
with early adoption permitted. The Company does not expect the
adoption of this ASU to have a material impact on its Consolidated
Financial Statements.


11





In
August 2016, the FASB issued ASU 2016-15, “Statement of Cash
Flows (Topic 230): Classification of Certain Cash Receipts and Cash
Payments,” which provides clarification on how certain cash
receipts and cash payments are presented and classified on the
statement of cash flows. This ASU is effective for annual and
interim periods beginning in 2018 and is required to be adopted
using a retrospective approach if practicable, with early adoption
permitted. The Company does not expect the adoption of this ASU to
have a material impact on its Consolidated Statement of Cash
Flows.


In
March 2016, the FASB issued ASU 2016-09, “Improvements to
Employee Share-Based Payment Accounting,” which seeks to
simplify accounting for share-based payment transactions including
income tax consequences, classification of awards as either equity
or liabilities, and the classification on the statement of cash
flows. The new standard requires the Company to recognize the
income tax effects of awards in the income statement when the
awards vest or are settled. The guidance is effective for fiscal
years beginning after December 15, 2016. Early adoption is
permitted and if an entity early adopts the guidance in an interim
period, any adjustments must be reflected as of the beginning of
the fiscal year that includes that interim period. The Company is
currently evaluating the impact of adopting this standard on its
Consolidated Financial Statements.


In
February 2016, the FASB issued ASU 2016-02, “Leases,” a
new lease standard requiring lessees to recognize lease assets and
lease liabilities for most leases classified as operating leases
under previous GAAP. The guidance is effective for fiscal years
beginning after December 15, 2018 with early adoption permitted.
The Company will be required to use a modified retrospective
approach for leases that exist or are entered into after the
beginning of the earliest comparative period in the financial
statements. The Company is currently evaluating the impact of
adopting this standard on its Consolidated Financial
Statements.


In
January 2016, the FASB issued ASU 2016-01, “Recognition and
Measurement of Financial Assets and Financial Liabilities,”
which changes certain guidance related to the recognition,
measurement, presentation and disclosure of financial instruments.
This update is effective for fiscal years beginning after December
15, 2017, including interim periods within those fiscal years.
Early adoption is not permitted for the majority of the update, but
is permitted for two of its provisions. The Company is evaluating
the new guidance and has not determined the impact this standard
may have on its Consolidated Financial Statements.


In May
2014, the FASB issued ASU 2014-09, “Revenue from Contracts
with Customers (Topic 606),” an update which removes inconsistencies in existing standards,
changes the way companies recognize revenue from contracts with
customers, and increases disclosure requirements. The guidance
requires companies to recognize revenue to depict the transfer of
goods or services to customers in amounts that reflect the
consideration to which the company expects to be entitled in
exchange for those goods or services. In March 2016, the FASB
issued guidance which provides further clarification on the
principal versus agent evaluation. The guidance is effective for
annual and interim periods beginning after December 15, 2017. The
standard is required to be adopted using either the full
retrospective approach, with all prior periods presented adjusted,
or the modified retrospective approach, with a cumulative
adjustment to retained earnings on the opening balance sheet. The
Company is currently evaluating the level of effort needed to
implement the standard, the impact of adopting this standard on its
Consolidated Financial Statements, and whether to use the full
retrospective approach or the modified retrospective
approach.


12





Recently Adopted


In
April 2015, the FASB issued ASU 2015-03, “Interest –
Imputation of Interest (Subtopic 835-30) – Simplifying the
Presentation of Debt Issuance Costs,” an update that requires
debt issuance costs to be presented in the balance sheet as a
direct reduction from the associated debt liability.  In
August 2015, the FASB subsequently issued ASU 2015-15,
“Interest – Imputation of Interest (Subtopic 835-30)
– Presentation and Subsequent Measurement of Debt Issuance
Costs Associated with Line-of-Credit Arrangements,” a
clarification as to the handling of debt issuance costs related to
line-of-credit arrangements that allows the presentation of these
costs as an asset. The standards update is effective for interim
and annual periods beginning after December 15, 2015. The Company
has debt costs associated with its line-of-credit only; therefore,
this standard had no impact on its Consolidated Financial
Statements. These costs remain an asset on the Company’s
Balance Sheet.


In
February 2015, the FASB issued ASU 2015-02, “Consolidation
(Topic 810) – Amendments to the Consolidation
Analysis,” an amendment to the guidance for determining
whether an entity is a variable interest entity
(“VIE”).  The standard does not add or remove
any of the five characteristics that determine if an entity is a
VIE.  However, it does change the manner in which a
reporting entity assesses one of the characteristics.  In
particular, when decision-making over the entity’s most
significant activities has been outsourced, the standard changes
how a reporting entity assesses if the equity holders at risk lack
decision making rights.  This standard is effective for
the Company for annual periods beginning after December 15,
2015 and early adoption is permitted, including in interim
periods.  The Company adopted this standard’s
update, as required, effective January 1, 2016. The adoption of
this standard’s update did not have a material impact on its
Consolidated Financial Statements.


NOTE
4 – FAIR VALUE MEASUREMENTS


Certain
financial instruments are reported at fair value on the
Consolidated Balance Sheets. Under fair value measurement
accounting guidance, fair value is defined as the amount that would
be received from the sale of an asset or paid for the transfer of a
liability in an orderly transaction between market participants,
i.e., an exit price. To estimate an exit price, a three-level
hierarchy is used. The fair value hierarchy prioritizes the inputs,
which refer broadly to assumptions market participants would use in
pricing an asset or a liability, into three levels. The Company
uses a market valuation approach based on available inputs and the
following methods and assumptions to measure the fair values of its
assets and liabilities, which may or may not be observable in the
market.


Fair Value of Financial Instruments (other
than Commodity Derivatives, see below) – The carrying
values of financial instruments, excluding commodity derivatives,
comprising current assets and current liabilities approximate fair
values due to the short-term maturities of these instruments and
are considered Level 1.


Derivatives – The fair values of
the Company’s commodity derivatives are considered Level 2 as
their fair values are based on third-party pricing models which
utilize inputs that are either readily available in the public
market, such as natural gas and oil forward curves and discount
rates, or can be corroborated from active markets or broker quotes.
These values are then compared to the values given by the
Company’s counterparties for reasonableness. The Company is
able to value the assets and liabilities based on observable market
data for similar instruments, which results in the Company using
market prices and implied volatility factors related to changes in
the forward curves. Derivatives are also subject to the risk that
counterparties will be unable to meet their obligations. Because
the Company’s commodity derivative counterparty was
Société Générale (“SocGen”) at
September 30, 2016, the Company considered non-performance risk in
the valuation of its derivatives to be minimal.


13





Financial
assets are considered Level 3 when their fair values are determined
using pricing models, discounted cash flow methodologies or similar
techniques, and at least one significant model assumption or input
is unobservable.





Fair value
measurements at September 30, 2016SignificantQuoted
prices
other
Significantin
active
observable
unobservablemarkets
inputs
inputs(Level
1)
(Level
2)
(Level
3)
TotalAssets:Commodity
derivatives – oil
$-
$1,194,307
$-
$1,194,307Liabilities:Commodity
derivatives – gas
$-
$78,763
$-
$78,763








Fair value
measurements at December 31, 2015SignificantQuoted
prices
other
Significantin
active
observable
unobservablemarkets
inputs
inputs(Level
1)
(Level
2)
(Level
3)
TotalAssets:Commodity
derivatives – oil
$-
$3,442,693
$-
$3,442,693Commodity
derivatives – gas
-
285,895
-
285,895Total
assets
$-
$3,728,588
$-
$3,728,588





Derivative
instruments listed above include swaps, reverse swaps and three-way
collars. For additional information on the Company’s
derivative instruments and derivative liabilities, see Note 5
– Commodity Derivative Instruments.


Debt – The Company’s debt
is recorded at the carrying amount on its Consolidated Balance
Sheets. For further discussion of the Company’s debt, please
see Note 9 – Debt and Interest Expense. The carrying
amount of floating-rate debt approximates fair value because the
interest rates are variable and reflective of market
rates.


Asset Retirement Obligations (“AROs”) –
The Company estimates the fair value of AROs based on discounted
cash flow projections using numerous estimates, assumptions and
judgments regarding such factors as the existence of a legal
obligation for an ARO, amounts and timing of settlements, the
credit-adjusted risk-free rate to be used and inflation
rates.





NOTE 5 – COMMODITY DERIVATIVE INSTRUMENTS





Objective and Strategies for Using Commodity Derivative
Instruments – In order to mitigate the effect of
commodity price uncertainty and enhance the predictability of cash
flows relating to the marketing of the Company’s crude oil
and natural gas, the Company enters into crude oil and natural gas
price commodity derivative instruments with respect to a portion of
the Company’s expected production. The commodity derivative
instruments used include variable to fixed price commodity swaps,
two-way and three-way collars.





While
these instruments mitigate the cash flow risk of future reductions
in commodity prices, they may also curtail benefits from future
increases in commodity prices.


14





The
Company elected to discontinue hedge accounting for all commodity
derivative instruments beginning with the 2013 financial year. The
balance in other comprehensive income (“OCI”) at
year-end 2012 remained in accumulated other comprehensive income
(“AOCI”) until the original hedged forecasted
transaction occurred. The last of these contracts expired in
December 2015 and the Company’s AOCI balance is now zero. No
mark-to-market adjustments for commodity derivative contracts are
made to AOCI, but instead are recognized in earnings. As a result
of discontinuing the application of hedge accounting, the
Company’s earnings are potentially more volatile. See
Note 4 – Fair Value Measurements for a discussion of
methods and assumptions used to estimate the fair values of the
Company’s commodity derivative instruments.





Counterparty Credit Risk –
Commodity derivative instruments expose the Company to counterparty
credit risk. The Company’s commodity derivative instruments
are with SocGen whose long-term senior unsecured debt is rated
“A” by Standard and Poor’s, “A2” by
Moody’s, “A” by Fitch, “A” by R&I
and “A(high)” by DBRS. Commodity derivative contracts
are executed under master agreements which allow the Company, in
the event of default, to elect early termination of all contracts.
If the Company chooses to elect early termination, all asset and
liability positions would be netted and settled at the time of
election.


Commodity
derivative instruments open as of September 30, 2016 are provided
below. Natural gas prices are New York Mercantile Exchange
(“NYMEX”) Henry Hub prices, 2016 crude oil prices are
Argus Light Louisiana Sweet (“LLS”), and 2017 crude oil
prices are NYMEX West Texas Intermediate
(“WTI”).


2016
2017Settlement
SettlementNATURAL GAS
(MMBtu):SwapsVolume
105,475
-Price
$2.646*
-3-way
collarsVolume
-
248,023Ceiling sold price
(call)
-
$3.280*Floor purchased
price (put)
-
$2.946*Floor sold price
(short put)
-
$2.381*CRUDE OIL
(Bbls):Put
spreadVolume
31,547
-Floor purchased
price (put)
$62.27
-Floor sold price
(short put)
$40.00
-3-way
collarsVolume
10,630
113,029Ceiling sold price
(call)
$47.15
$77.00Floor purchased
price (put)
$40.00
$60.00Floor sold price
(short put)
$30.00
$45.00





*Price is a
weighted average





15





Derivatives
for each commodity are netted on the Consolidated Balance Sheets as
they are all contracts with the same counterparty. The following
table presents the fair value and balance sheet location of each
classification of commodity derivative contracts on a gross basis
without regard to same-counterparty netting:


Fair value as
ofSeptember
30,
December
31,2016
2015Asset commodity
derivatives:Current
assets
$1,420,921
$3,069,115Noncurrent
assets
326,656
1,841,1201,747,577
4,910,235Liability commodity
derivatives:Current
liabilities
(478,669)
(411,068)Noncurrent
liabilities
(153,364)
(770,579)(632,033)
(1,181,647)Total commodity
derivative instruments
$1,115,544
$3,728,588







Sales
of natural gas and crude oil on the Consolidated Statements of
Operations are comprised of the following:





Three Months
Ended
Nine Months
EndedSeptember
30,
September
30,2016
2015
2016
2015Sales of natural
gas and crude oil
$3,151,626
$4,649,009
$9,207,636
$14,756,582Gain realized from
sale of commodityderivatives
-
-
-
4,030,000Other gains
(losses) realized oncommodity
derivatives
488,409
432,825
2,205,216
1,084,610Unrealized gains
(losses) oncommodity
derivatives
(40,473)
3,460,825
(2,613,044)
(1,847,371)Total revenue from
natural gas and crude oil
$3,599,562
$8,542,659
$8,799,808
$18,023,821





A
reconciliation of the components of accumulated other comprehensive
income (loss) in the Consolidated Statements of Changes in Equity
is presented below:





Nine Months
Ended
Year
EndedSeptember 30,
2016
December 31,
2015Before
tax
After
tax
Before
tax
After
taxBalance, beginning
of period
$-
$-
$63,091
$38,801Sale of unexpired
contracts previously subjectto
hedge accounting rules
-
-
(119,917)
(73,749)Other
reclassifications due to expired contractspreviously subject
to hedge accounting rules
-
-
56,826
34,948Balance, end of
period
$-
$-
$-
$-





NOTE 6 – ASSET IMPAIRMENTS





Oil and
natural gas prices have remained low in the first three quarters of
2016 and, as a result, the Company recognized a non-cash asset
impairment charge of $11,015,589 to write down oil and gas
properties for the three months ended June 30, 2016. In addition,
the Company recognized a non-cash asset impairment of $4,927,508 to
write off goodwill for the three months ended June 30, 2015. The
Company did not incur an impairment for the three months ended
September 30, 2016.


16








NOTE 7 – PREFERRED STOCK





The Company’s shares of 9.25% Series A Cumulative Redeemable
Preferred Stock, no par value per share, with a liquidation
preference of $25.00 per share (the “Series A Preferred
Stock”), traded on the NYSE MKT under the symbol
“YUMAprA” prior to the Series A Conversion. Holders of
the Series A Preferred Stock were entitled to receive, when, as and
if declared by the Board of Directors, cumulative dividends at the
rate of 9.25% per annum (the dividend rate) based on the
liquidation price of $25.00 per share of the Series A
Preferred Stock, payable monthly in arrears on each dividend
payment date, with the first payment date of December 1, 2014. The
Series A Preferred Stock is presented in the permanent equity
section of the financial statements. Due to the current depressed
commodity price environment, as well as other factors which have
adversely affected the Company’s cash flows and liquidity,
the monthly dividends on the Series A Preferred Stock were
suspended beginning with the month ended November 30, 2015.
Pursuant to the Company’s credit facility, the Company was
precluded from making dividend payments on its Series A Preferred
Stock. The Company’s articles of incorporation as of
September 30, 2016 provided that any unpaid dividends will
accumulate. While the accumulation did not result in presentation
of a liability on the balance sheet, the accumulated dividends were
deducted from the Company’s net income (or added to its net
loss) in the determination of income (loss) attributable to common
shareholders and, as appropriate, the corresponding computation of
earnings (loss) per share. As of September 30, 2016, the Company
had accumulated a total of $1,175,628 in unpaid preferred stock
dividends, attributable to the Series A Preferred Stock. As part of
the Reincorporation Merger, the Series A Preferred Stock, including
all of the accumulated and unpaid dividends, was converted into
common stock. See Note 15 – Subsequent Events for additional
information.





NOTE 8 – EARNINGS (LOSS) PER COMMON SHARE





Earnings (loss) per
common share is computed by dividing earnings or losses
attributable to common stockholders by the weighted average number
of shares of common stock outstanding during the period. Potential
common stock equivalents are determined using the “if
converted” method.


Potentially
dilutive securities for the computation of diluted weighted average
shares outstanding (adjusted for the 1-for-20 reverse stock split
as described in Note 15 – Subsequent Events) are as
follows:


Three Months
Ended
Nine Months
EndedSeptember
30,
September
30,2016
2015
2016
2015Restricted Stock
Awards
74,261
78,716
99,315
68,691Restricted Stock
Units
-
4,771
-
4,77174,261
83,487
99,315
73,462





For the
three months ended September 30, 2016 and the three months ended
September 30, 2015, adjusted earnings were losses, therefore common
stock equivalents were excluded from the calculation of diluted net
loss per share of common stock, as their effect was anti-dilutive.
RSUs were settled in cash during April 2016 and are therefore no
longer potentially dilutive.


17





NOTE 9 – DEBT AND INTEREST EXPENSE





September
30,
December
31,2016
2015Variable rate
revolving credit agreement payable to Société
Générale,CIT Bank, NAC, and
LegacyTexas Bank, maturing October 31, 2017,secured by the
stock of Exploration and its interest in POL, andguaranteed by The
Yuma Companies, Inc.
$29,800,000
$29,800,000Installment loan
due February 29, 2016, originating from thefinancing of
insurance premiums at 3.74% interest rate.
-
108,894Installment loan
due June 11, 2016, originating from thefinancing of
insurance premiums at 3.76% interest rate.
-
154,74129,800,000
30,063,635Less: current
portion
(29,800,000)
(30,063,635)Total long-term
debt
$-
$-





The
Company has borrowings which require, among other things,
compliance with certain financial ratios. Due to operating losses
the Company has sustained during recent quarters as a result of the
prolonged weak commodity price environment and other factors, the
Company was not in compliance with the trailing four quarter funded
debt to EBITDA financial ratio covenant under its credit facility
at September 30, 2015, December 31, 2015, March 31, 2016, June 30,
2016 and September 30, 2016, its current ratio as of June 30, 2016
and September 30, 2016, as well as its EBITDA to interest expense
ratio as of December 31, 2015, March 31, 2016, June 30, 2016 and
September 30, 2016. In addition, the Company was not in compliance
due to its going concern opinion at March 31, 2016 and June 30,
2016, as well as its failure to maintain a certain financial bank
as its principal depository bank. On May 20, 2016, the Company
remedied its compliance with regard to the depository bank. On
December 30, 2015, Exploration entered into the Ninth Amendment to
the credit agreement which provided for a $29.8 million conforming
borrowing base, with an automatic reduction to $20.0 million on May
31, 2016, and waived the compliance with the trailing four quarter
funded debt to EBITDA and EBITDA to interest expense financial
ratio covenants or any other events of default under the credit
facility for the quarters ended September 30, 2015 and December 31,
2015. On June 6, 2016 and effective as of May 31, 2016, Exploration
entered into the Tenth Amendment as amended on August 25, 2016,
which maintained the borrowing base at $29.8 million and
automatically reduced the borrowing base to $20.0 million on the
earliest of (i) September 23, 2016, if the Form S-4 filed with the
SEC pursuant to the pending Merger Agreement had not been declared
effective by such date; (ii) the date that was forty-seven days
after the date the Form S-4 had been declared effective by the SEC;
(iii) October 31, 2016; and (iv) in the event of the termination of
the merger agreement. As of September 30, 2016, the Company had a
working capital deficit of $32.5 million inclusive of the
Company’s outstanding debt under its credit facility, which
was fully drawn with no additional borrowing capacity
available.


Upon
the closing of the Merger discussed in Note 15 – Subsequent
Events, the outstanding balance under the credit facility was
assumed by Yuma Delaware in a new credit facility. Under the new
credit facility, which was entered into in connection with the
Merger, Yuma Delaware is in compliance with the credit facility.
This new credit facility supersedes the Company’s previous
credit agreement and non-compliance matters discussed
above.


18





The
following summarizes interest expense for the three and nine months
ended September 30, 2016 and 2015.


Three Months
Ended
Nine Months
EndedSeptember
30,
September
30,2016
2015
2016
2015Credit
agreement
$323,735
$314,177
$841,112
$835,584Credit agreement
commitment fees
-
6,301
-
31,460Amortization
ofcredit
agreement loan costs
60,489
73,146
518,479
209,903Insurance
installment loan
-
4,400
1,961
9,597Other interest
charges
3,066
39
8,095
1,062Capitalized
interest
(141,931)
(266,949)
(395,244)
(750,107)Total interest
expense
$245,359
$131,114
$974,403
$337,499





NOTE 10 – MERGER WITH PYRAMID OIL COMPANY AND
GOODWILL





On September 10, 2014, a wholly owned subsidiary of Pyramid merged
with and into Yuma Energy, Inc., a Delaware corporation
(“Yuma Co.”), in exchange for 66,336,701 shares of
common stock (prior to the 1-for-20 reverse stock split as
described in Note 15 – Subsequent Events) and Pyramid changed its name to “Yuma
Energy, Inc.” (the “Pyramid merger”). As a result
of the Pyramid merger, the former Yuma Co. stockholders received
approximately 93% of the then outstanding common stock of the
Company and thus acquired voting control. Although the Company was
the legal acquirer, for financial reporting purposes the Pyramid
merger was accounted for as a reverse acquisition of Pyramid by
Yuma Co. The transaction qualified as a tax-deferred reorganization
under Section 368(a) of the Internal Revenue Code of 1986, as
amended (the “Code”).





The
Pyramid merger was accounted for as a business combination in
accordance with ASC 805 Business Combinations (“ASC
805”). ASC 805, among other things, requires assets acquired
and liabilities assumed to be measured at their acquisition date
fair values. Goodwill represents the excess of the purchase price
over the estimated fair value of the assets acquired net of the
fair value of liabilities assumed in an acquisition. Certain assets
and liabilities may be adjusted as additional information is
obtained; but no later than one year from the acquisition date. The
provisions of ASC 350, on Intangibles – Goodwill and Other
require that intangible assets with indefinite lives, including
goodwill, be evaluated on an annual basis for impairment, or more
frequently if events occur or circumstances change that could
potentially result in impairment. The goodwill impairment test
requires the allocation of goodwill and all other assets and
liabilities to reporting units; however, the Company has only one
reporting unit.





The
drop in crude oil prices and the resulting decline in the
Company’s common share price since the Pyramid merger caused
the Company to test goodwill for impairment at June 30, 2015.
Goodwill was determined to be fully impaired and as a result, the
balance of $4,927,508 was written off at that time.


19





NOTE
11 – INCOME TAXES


The
following summarizes the income tax expense (benefit) and effective
tax rates:


Three Months
Ended
Nine Months
EndedSeptember
30,
September
30,2016
2015
2016
2015Consolidated net
income (loss)before
income taxes
$(2,162,873)
$239,243
$(22,135,882)
$(16,928,915)Income tax expense
(benefit)
(47,429)
329,653
(1,272,664)
(3,605,839)Effective tax
rate
2.2%
138%
5.7%
21.3%





The
differences between the U.S. federal statutory rate of 34% and the
Company’s effective tax rates for the three and nine months
ended September 30, 2016 and 2015 are due primarily to state taxes
and nondeductible expenses. In addition, September 30, 2016 was
impacted by the expected valuation allowance on our deferred tax
asset at year-end, which affected our expected annual effective tax
rate and the tax effect of nondeductible stock
compensation.


The
Company knows of no uncertain tax positions and has no unrecognized
tax benefits for the nine months ended September 30, 2016 or
September 30, 2015. Valuation allowances are established when the
Company determines it is more likely than not that some portion, or
all, of the deferred tax assets will not be realized. As of
September 30, 2016, the Company anticipates that it will have a net
deferred tax asset at year-end 2016, for which a valuation
allowance will be required. The Company has considered the effect
of the valuation allowance in the current period in determining its
expected annual effective tax rate to record tax expense for the
period ending September 30, 2016. No valuation allowance was
established as of September 30, 2015.





NOTE
12 – CONTINGENCIES


Certain Legal Proceedings


From
time to time, the Company is party to various legal proceedings
arising in the ordinary course of business. While the outcome of
lawsuits cannot be predicted with certainty, the Company is not
currently a party to any proceeding that it believes, if determined
in a manner adverse to the Company, could have a potential material
adverse effect on its financial condition, results of operations,
or cash flows.





Amanda Olivier, et al. v. Nabors Drilling USA, L.P., and Yuma
Exploration and Production, Inc.





On July
9, 2014, Nabors Drilling USA, L.P. and other Nabors entities and
Yuma Energy, Inc. and several of its wholly owned subsidiaries were
named in a lawsuit filed in the District Court of Harris County,
Texas, in the 80th Judicial District,
concerning the death of an employee of Timco Services during the
drilling of the Crosby 12-1 well. All of the Yuma-related entities,
except for Exploration, were voluntarily dismissed from the lawsuit
by the Plaintiffs. The Company has tendered its defense to its
liability insurance carriers who are responding. There has been one
unsuccessful mediation session. Depositions are still ongoing.
Defense counsel intends to file a motion seeking dismissal of the
claims against Exploration, which is currently being finalized.
Management believes that the Company is not liable, and has
adequate insurance to meet any potential claim from this
suit.


Ontiveros v. Pyramid Oil,
LLC, Yuma Energy, Inc. et al.


In
September 2015, a suit was filed against the Company and Pyramid
Oil LLC styled Mark A. Ontiveros and Louise D. Ontiveros, Trustees
of The Ontiveros Family Trust dated March 29, 2007 vs. Pyramid Oil,
LLC, et al., Case Number 15CV02959 in the Superior Court of
California, County of Santa Barbara, Cook Division. In the suit,
the plaintiffs allege that the 1950 Community Oil and Gas Lease
between them and Pyramid Oil LLC has expired by
non-production.  The Company claims that the lease is still in
effect, as there is no cessation of production time frame set out
in the lease; production had temporarily ceased, but was still
profitable when measured over an appropriate time period; and the
Company was conducting workover operations on a well on the lease
in an effort to re-establish production when served with the quit
claim deed demand from the plaintiff’s attorney.  All
present owners of the minerals covered by the 1950 Community Oil
and Gas Lease, with the exception of the plaintiffs, have executed
amendments signifying their concurrence that the 1950 Community Oil
and Gas Lease is still in force and effect.  On June 23, 2016,
Pyramid Oil LLC filed a First Amended Cross Complaint against
Texican Energy Corporation and Everett Lawley alleging interference
with contractual relations and prospective economic relations, and
violation of the California Uniform Trade Secrets Act. The parties
are presently in the process of document discovery.Management intends
to defend the plaintiffs’ claims and pursue the cross claim
vigorously.


20








Yuma Energy, Inc. v. Cardno PPI Technology Services, LLC
Arbitration





On May
20, 2015, counsel for Cardno PPI Technology Services, LLC
(“Cardno PPI”) sent a notice of the filing of liens
totaling $304,209 on the Company’s Crosby 14 No. 1 Well and
Crosby 14 SWD No. 1 Well in Vernon Parish, Louisiana. The Company
disputed the validity of the liens and of the underlying invoices,
and notified Cardno PPI that applicable credits had not been
applied. The Company invoked mediation on August 11, 2015 on the
issues of the validity of the liens, the amount due pursuant to
terms of the parties’ Master Service Agreement
(“MSA”), and PPI Cardno’s breaches of the MSA.
Mediation was held on April 12, 2016; no settlement was
reached.





On May
12, 2016, Cardno filed a lawsuit in Louisiana state court to
enforce the liens; the Court entered an Order Staying Proceeding on
June 13, 2016, ordering that the lawsuit “be stayed pending
mediation/arbitration between the parties.” On June 17, 2016,
the Company served a Notice of Arbitration on Cardno PPI, stating
claims for breach of the MSA billing and warranty provisions. On
July 15, 2016, Cardno PPI served a Counterclaim for $304,209 plus
attorneys’ fees. The parties are currently engaged in the
arbitrator selection process. Management intends to pursue the
Company’s claims and to defend the counterclaim
vigorously.





Environmental Remediation Contingencies





As of
September 30, 2016, there were no known environmental or other
regulatory matters related to the Company’s operations that
were reasonably expected to result in a material liability to the
Company. The Company’s operations are subject to numerous
laws and regulations governing the discharge of materials into the
environment or otherwise relating to environmental
protection.





Board of Commissioners of the Southeast Louisiana Flood Protection
Authority-East, et al. v. Tennessee Gas Pipeline Company, LLC, et
al.





Exploration,
a subsidiary of the Company, has been named as one of 97 defendants
in a matter entitled Board of Commissioners of the Southeast
Louisiana Flood Protection Authority – East, Individually and
As the Board Governing the Orleans Levee District, the Lake Borgne
Basin Levee District, and the East Jefferson Levee District v.
Tennessee Gas Pipeline Company, LLC, et al., Civil District Court
for the Parish of Orleans, State of Louisiana, No. 13-6911,
Division “J” - 5, now removed as Civil Action No.
13-5410, before the United States District Court, Eastern District
of Louisiana. Plaintiff filed the suit on July 24, 2013 seeking
damages and injunctive relief arising out of defendants’
drilling, exploration, and production activities from the early
1900s to the present day in coastal areas east of the Mississippi
River in Southeast Louisiana.


21








The
suit alleges that defendants’ activities have caused
“removal, erosion, and submergence” of coastal lands
resulting in significant reduction or loss of the protection such
lands afforded against hurricanes and tropical storms. Plaintiff
alleges that it now faces increased costs to maintain and operate
the man-made hurricane protection system and may reach the point
where that system no longer adequately protects populated
areas.





Plaintiff
lists hundreds of wells, pipelines, and dredging events as possible
sources of the alleged land loss. Exploration is named in
association with 11 wells, four rights-of-way, and one dredging
permit. The suit does not specify any deficiency or harm caused by
any individual activity or facility.





Although
the suit references various federal statutes as sources of
standards of care, plaintiff claims that all causes of action arise
under state law: negligence, strict liability, natural servitude of
drain, public nuisance, private nuisance, and as third-party
beneficiary under breach of contract.





The
Company tendered its defense to its liability insurance carriers,
who are responding. On February 13, 2015, the federal judge
adjudicating the matter granted defendants “Joint Motion to
Dismiss for Failure to State a Claim Under Rule 12(b)(6)”,
thereby dismissing plaintiff’s claims with prejudice in the
matter. On February 20, 2015, the Board of Orleans filed a notice
of appeal to the U.S. Fifth Circuit. On February 29, 2016, oral
arguments were held regarding the appeal, but as of July 31, 2016,
no ruling on the appeal has been made. The Company will continue to
contest plaintiff’s legal arguments and factual assertions.
At this point in the legal process, no evaluation of the likelihood
of an unfavorable outcome or associated economic loss can be made;
therefore no liability has been recorded on the Company’s
books.





Vintage Assets, Inc. v. Tennessee Gas Pipeline, L.L.C. et
al.





On
October 24, 2016, Texas Southeastern Gas Gathering Company
(“TGG”), a subsidiary of the Company, was named as a
defendant in an action by Vintage Assets, Inc. in the United States
District Court for the Eastern District of Louisiana. Vintage
claims that its property, located in Plaquemines Parish, has been
damaged by the widening of canals used by the defendants. Between
1953 and 1970, the defendants’ predecessors received multiple
right-of-way servitudes on Vintage’s property, which
authorized the construction and operation of pipelines and dredge
canals. The defendants dredged canals and laid pipelines pursuant
to the rights of way agreements. Vintage alleges that its property
has suffered damage because of defendants’ failure to
maintain the pipeline canals and banks. Further Vintage alleges
that this failure has caused ecological damages and loss of acreage
due to erosion. The action is currently scheduled for trial in
September 2017. Management intends to defend the plaintiffs’
claims vigorously and has notified its insurance carrier of the
claim.  TGG sold all of its assets to High Point Gas Gathering
in 2010.  At this point in the legal process, no evaluation of
the likelihood of an unfavorable outcome or associated economic
loss can be made; therefore no liability has been recorded on the
Company’s books.





The Parish of St. Bernard v. Atlantic Richfield Co., et
al





On
October 13, 2016, two subsidiaries of the Company, Exploration and
Yuma Petroleum Company (“YPC”), were named as
defendants, among several other defendants, in an action by the
Parish of St. Bernard in the Thirty-Fourth Judicial District of
Louisiana. The petition alleges violations of the State and Local
Coastal Resources Management Act of 1978, as amended, in the St.
Bernard Parish.  The Company has notified its insurance
carrier of the lawsuit.  Management intends to defend the
plaintiffs’ claims vigorously.  At this point in the
legal process, no evaluation of the likelihood of an unfavorable
outcome or associated economic loss can be made; therefore no
liability has been recorded on the Company’s
books.





22





Audits


Louisiana, et al. Escheat Tax Audits


The
States of Louisiana, Texas, Minnesota, North Dakota and Wyoming
have notified the Company that they will examine the
Company’s books and records to determine compliance with each
of the examining state’s escheat laws. The review is being
conducted by Discovery Audit Services, LLC. The Company has engaged
Ryan, LLC to represent it in this matter. The exposure related to
the audits is not currently determinable.


Louisiana Severance Tax Audit


The
State of Louisiana, Department of Revenue, notified Exploration
that it was auditing Exploration’s calculation of its
severance tax relating to Exploration’s production from
November 2012 through March 2016. The audit relates to the
Department of Revenue’s recent interpretation of
long-standing oil purchase contracts to include a disallowable
“transportation deduction,” and thus to assert that the
severance tax paid on crude oil sold during the contract term was
not properly calculated. Exploration is currently waiting on the
Department of Revenue’s final audit results. The exposure
related to this audit is not currently determinable.


NOTE 13 – GREATER MASTERS CREEK FIELD AREA





During
the first quarter of 2016, the Company shut-in 14 Austin Chalk
wells in Beauregard, Rapides and Vernon Parishes, Louisiana due to
low oil and natural gas prices. Since production was not restarted
from these wells, the associated leases have expired, reducing the
Company’s proved reserves from year-end 2015 by approximately
1,629 MBoe, acreage by 22,021 gross (18,140 net) acres, operated
proved undeveloped locations by three, and operated non-proved
undeveloped locations by seven.





In
addition, during the first quarter of 2016, the Company received
notice from the operator of certain wells in Rapides and Vernon
Parishes, Louisiana, that certain wells in which the Company has an
interest were shut-in due to current economic conditions. The
operator has since sold its interest. The subsequent operator has
not restarted production from eight of these wells, and the leases
associated with the shut-in wells have expired, reducing the
Company’s acreage by 4,686 gross (1,389 net)
acres.





In
April 2016, a party to the participation agreement dated July 31,
2013 relating to the Company’s Greater Masters Creek Area
exercised its option to participate under the participation
agreement for a four percent working interest.


On
April 4, 2016, the Company entered into an amendment effective
March 1, 2016 to an oil and gas lease in the Greater Masters Creek
Field area with a certain mineral owner for acreage that was not
held by production as of March 31, 2016. The total acreage is
approximately 25,139 acres and, by virtue of the Company conducting
certain location clean-up operations, the lease has now been
extended until December 31, 2016. This extension is subject to
certain additional performance criteria, including the posting of a
bond to cover P&A costs for wells located on this mineral
owner’s property, and plugging and abandoning six of the
mineral owner’s wells by December 31, 2016 at an estimated
net cost of $426,000. The lease may be extended until June 30, 2017
by paying a rental of $628,450, or by spudding a new well before
December 31, 2016. If the leased acreage expires, the
Company’s proved reserves from year-end 2015 would be reduced
by approximately 5,096 MBoe, the number of operated proved
undeveloped locations and operated non-proved locations would be
reduced by 13 and 16, respectively.


23








NOTE 14 – TEXAS SOUTHEASTERN GAS MARKETING
COMPANY





As of
January 1, 2016, the Company decided to discontinue the operations
of Texas Southeastern Gas Marketing Company due to the limited
volumes of natural gas that it marketed, as well as the costs
associated with accounting for the entity. Texas Southeastern Gas
Marketing Company is not a significant subsidiary, and this
discontinuation of operations does not represent a strategic shift
in business for the Company.





NOTE 15 – SUBSEQUENT EVENTS





The
Company is not aware of any subsequent events which would require
recognition or disclosure in the financial statements, except as
noted below or already recognized or disclosed in the
Company’s filings with the SEC.


Davis Agreement and Plan of Merger and Reorganization


On
October 26, 2016, the shareholders of the Company approved, among
other proposals, (i) the conversion (the “Series A
Conversion”) of the 9.25% Series A Cumulative Redeemable
Preferred Stock, no par value per share of the Company (the
“Series A Preferred Stock”), into common stock, no par
value per share of the Company (the “common stock”), at
a rate of 35 shares of common stock for each share of Series A
Preferred Stock; (ii) the reincorporation of the Company from
California to Delaware pursuant to a merger (the
“Reincorporation Merger”) of the Company with and into
Yuma Energy, Inc., a Delaware corporation and wholly owned
subsidiary of the Company (“Yuma Delaware”); and (iii)
the merger (the “Merger”) of Yuma Merger Subsidiary,
Inc., a Delaware corporation and wholly owned subsidiary of Yuma
Delaware (“Merger Subsidiary”), with and into Davis
Petroleum Acquisition Corp., a Delaware corporation
(“Davis”) with Davis surviving as a wholly owned
subsidiary of Yuma Delaware. The Company issued approximately
19,411,000 shares of common stock as a result of the Series A
Conversion. Immediately following the Series A Conversion, each
share of common stock was exchanged for one-twentieth of one share
of common stock, $0.001 par value per share of Yuma Delaware (the
“Yuma Delaware Common Stock”) as part of the
Reincorporation Merger.


New Credit Facility


Upon
the closing of the Merger discussed above, the entire outstanding
balance under the credit facility was assumed by Yuma Delaware in a
new credit facility (“the Credit Agreement”). The
Credit Agreement provides for a $75.0 million 3-year revolving
credit facility with SG Americas Securities, LLC (“SG
Americas”) as Lead Arranger and Bookrunner, SocGen as
Administrative Agent and the lenders party thereto. The Credit
Agreement replaces the Company’s existing credit agreement.
The initial borrowing base of the Credit Agreement is $44.0
million, and is subject to redetermination as of January 1, 2017 as
well as April 1st and October 1st of each year. As of October 26,
2016, Yuma Delaware had approximately $39.5 million outstanding
under the Credit Agreement. The incremental $9.7 million of debt
outstanding at October 26, 2016 under the new Credit Agreement from
the Company's outstanding debt balance of $29.8 million at
September 30, 2016 was primarily the result of paying off Davis'
outstanding debt balance of $9.0 million at Bank of America,
accrued interest under the old credit facilities, as well as fees
associated with the new Credit Agreement. All of the obligations
under the Credit Agreement, and the guarantee of those obligations,
are secured by substantially all of the assets of Yuma Delaware and
customary financial covenants have been made.





24





Item
2.
 Management’s
Discussion and Analysis of Financial Condition and Results of
Operations.





The following discussion and analysis of our financial condition
and results of operations should be read in conjunction with the
accompanying unaudited consolidated financial statements and
related notes thereto, included in Part I, Item 1 of this Quarterly
Report on Form 10-Q and should further be read in conjunction with
our Annual Report on Form 10-K/A for the year ended December 31,
2015.





Cautionary Statement Regarding Forward-Looking
Statements





Certain
statements contained in this Quarterly Report on Form 10-Q may
contain “forward-looking statements” within the meaning
of Section 27A of the Securities Act of 1933, as amended (the
“Securities Act”), and Section 21E of the
Securities Exchange Act of 1934, as amended (the “Exchange
Act”). All statements other than statements of historical
facts contained in this report are forward-looking statements.
These forward-looking statements can generally be identified by the
use of words such as “may,” “will,”
could,” “should,” “project,”
“intends,” “plans,” “pursue,”
“target,” “continue,”
“believes,” “anticipates,”
“expects,” “estimates,”
“predicts,” or “potential,” the negative of
such terms or variations thereon, or other comparable terminology.
Statements that describe our future plans, strategies, intentions,
expectations, objectives, goals or prospects are also
forward-looking statements. Readers should consider carefully the
risks described in the “Risk Factors” section included
in our Annual Report on Form 10-K/A for the fiscal year ended
December 31, 2015, and the other disclosures contained herein and
therein, which describe factors that could cause our actual results
to differ from those anticipated in forward-looking statements,
including, but not limited to, the following factors:





●
 our ability to
repay outstanding loans when due;





●
 our limited
liquidity and ability to finance our exploration, acquisition and
development strategies;





●
 reductions in the
borrowing base under our credit facility;





●
 impacts to our
financial statements as a result of oil and natural gas property
impairment write-downs;





●
 volatility and
weakness in commodity prices for oil and natural gas and the effect
of prices set or influenced by action of the Organization of the
Petroleum Exporting Countries (“OPEC”) and other Middle
Eastern producers who are not OPEC members, Africa and
Russia;





●
 our ability to
improve and implement changes to our internal controls over
financial reporting;





●
 our ability to
successfully integrate acquired oil and natural gas businesses and
operations;


●
 the possibility
that acquisitions and divestitures may involve unexpected costs or
delays, and that acquisitions may not achieve intended benefits and
will divert management’s time and energy, which could have an
adverse effect on our financial position, results of operations, or
cash flows;


●
 risks in connection
with potential acquisitions and the integration of significant
acquisitions;





25





●
 we may incur more
debt; higher levels of indebtedness make us more vulnerable to
economic downturns and adverse developments in our
business;


●
 our ability to
successfully develop our inventory of undeveloped acreage in our
resource plays;


●
 our oil and natural
gas assets are concentrated in a relatively small number of
properties;


●
 access to adequate
gathering systems, processing facilities, transportation take-away
capacity to move our production to market and marketing outlets to
sell our production at market prices;


●
 our ability to
generate sufficient cash flow from operations, borrowings or other
sources to enable us to fund our operations, satisfy our
obligations and seek to develop our undeveloped acreage
positions;


●
 our ability to
replace our oil and natural gas reserves;


●
 the presence or
recoverability of estimated oil and natural gas reserves and actual
future production rates and associated costs;


●
 the potential for
production decline rates for our wells to be greater than we
expect;


●
 our ability to
retain key members of senior management and key technical
employees;


●
 environmental
risks;


●
 drilling and
operating risks;


●
 exploration and
development risks;


●
 the possibility
that our industry may be subject to future regulatory or
legislative actions (including additional taxes and changes in
environmental regulations);


●
 general economic
conditions, whether internationally, nationally or in the regional
and local market areas in which we do business, may be less
favorable than we expect, including the possibility that economic
conditions in the United States will worsen and that capital
markets are disrupted, which could adversely affect demand for oil
and natural gas and make it difficult to access
capital;


●
 social unrest,
political instability or armed conflict in major oil and natural
gas producing regions outside the United States, such as Africa,
the Middle East, and armed conflict or acts of terrorism or
sabotage;


●
 other economic,
competitive, governmental, regulatory, legislative, including
federal, state and tribal regulations and laws, geopolitical and
technological factors that may negatively impact our business,
operations or oil and natural gas prices;


●
 the insurance
coverage maintained by us may not adequately cover all losses that
may be sustained in connection with our business
activities;


●
 title to the
properties in which we have an interest may be impaired by title
defects;


●
 management’s
ability to execute our plans to meet our goals;


●
 the cost and
availability of goods and services, such as drilling rigs;
and


●
 our dependency on
the skill, ability and decisions of third party operators of the
oil and natural gas properties in which we have a non-operated
working interest.





26





All
forward-looking statements are expressly qualified in their
entirety by the cautionary statements in this paragraph and
elsewhere in this document. Other than as required under the
securities laws, we do not assume a duty to update these
forward-looking statements, whether as a result of new information,
subsequent events or circumstances, changes in expectations or
otherwise.





Overview





Yuma
Energy, Inc. is an independent Houston-based exploration and
production company. We are focused on the acquisition, development,
and exploration for conventional and unconventional oil and natural
gas resources, primarily in the U.S. Gulf Coast and California.
Prior to the Reincorporation Merger, we were incorporated in
California on October 7, 1909. We have employed a 3-D seismic-based
strategy to build a multi-year inventory of development and
exploration prospects. Our current operations are focused on
onshore assets located in central and southern Louisiana, where we
are targeting the Austin Chalk, Tuscaloosa, Wilcox, Frio, Marg Tex
and Hackberry formations. In addition, we have a non-operated
position in the Bakken Shale in North Dakota and operated positions
in Kern and Santa Barbara Counties in California. Our common stock
is traded on the NYSE MKT under the trading symbol
“YUMA.” Our Series A Preferred Stock was traded on the
NYSE MKT under the trading symbol “YUMAprA” prior to
the Series A Conversion discussed below.





Recent Developments





Agreement and Plan of Merger and Reorganization





On
October 26, 2016, the shareholders of the Company approved, among
other proposals, (i) the conversion (the “Series A
Conversion”) of the 9.25% Series A Cumulative Redeemable
Preferred Stock, no par value per share of the Company (the
“Series A Preferred Stock”), into common stock, no par
value per share of the Company (the “common stock”), at
a rate of 35 shares of common stock for each share of Series A
Preferred Stock; (ii) the reincorporation of the Company from
California to Delaware pursuant to a merger (the
“Reincorporation Merger”) of the Company with and into
Yuma Energy, Inc., a Delaware corporation and wholly owned
subsidiary of the Company (“Yuma Delaware”); and (iii)
the merger (the “Merger”) of Yuma Merger Subsidiary,
Inc., a Delaware corporation and wholly owned subsidiary of Yuma
Delaware (“Merger Subsidiary”), with and into Davis
Petroleum Acquisition Corp., a Delaware corporation
(“Davis”) with Davis surviving as a wholly owned
subsidiary of Yuma Delaware. The Company issued approximately
19,411,000 shares of common stock as a result of the Series A
Conversion. Immediately following the Series A Conversion, each
share of common stock was exchanged for one-twentieth of one share
of common stock, $0.001 par value per share of Yuma Delaware (the
“Yuma Delaware Common Stock”) as part of the
Reincorporation Merger. Upon the closing of the Merger, the
outstanding balance under the credit facility was assumed by Yuma
Delaware as part of a new credit facility.





Commodity Prices





The
prices of crude oil and natural gas have declined dramatically
since mid-year 2014, having recently reached multiyear lows during
the first quarter of 2016, as a result of robust supply growth,
weakening demand in emerging markets, and OPEC’s decision to
continue to produce at current levels. These market dynamics have
led many to conclude that commodity prices are likely to remain
lower for a prolonged period. In response to these developments,
among other things, we have reduced our spending and believe that
the Merger will increase our liquidity and improve our financial
position (see Item 1. Unaudited Condensed Notes to the Consolidated
Financial Statements, Note 15 – Subsequent Events). In
addition, we are continuing to actively explore and evaluate
various strategic alternatives, including asset sales, to reduce
the level of our debt and lower our future cash interest
obligations. We believe that a reduction in our debt and cash
interest obligations on a per barrel basis is needed to improve our
financial position and flexibility and to position us to take
advantage of opportunities that may arise out of the current
industry downturn.


27








Full Cost Ceiling Test Impairment





Oil and
natural gas prices have remained low in the first three quarters of
2016 and, as a result, we recognized an $11.0 million non-cash
asset impairment in the second quarter of 2016 which has negatively
impacted our results of operations and equity.  We did not
incur an impairment in the third quarter of 2016.  If prices
remain at current levels, subject to numerous factors and inherent
limitations, and all other factors remain constant, the Company
(stand-alone, pre-merger) does not expect to incur a non-cash full
cost impairment during the fourth quarter of 2016.  There are
numerous uncertainties inherent in the estimation of proved
reserves and accounting for oil and natural gas properties in
future periods.  Our estimated fourth-quarter 2016 full cost
ceiling calculation has been prepared by substituting (i) $42.47
per barrel for oil, and (ii) $2.48 per MMBtu for natural gas for
the expected realized prices as of December 31, 2016. The
forecasted average realized price was based on the average realized
price for sales of crude oil, natural gas liquids and natural gas
on the first calendar day of each month for the first 11 months and
an estimate for the twelfth month based on a quoted forward price.
Changes to our reserves and future production were made due to
changing the effective date of the evaluation from September 30,
2016 to December 31, 2016. All other inputs and assumptions have
been held constant. Accordingly, this estimate accounts for the
impact of more current commodity prices in the fourth quarter of
2016 utilized in our full cost ceiling calculation.





Critical Accounting Policies





Critical accounting
policies are defined as those that are reflective of significant
judgments and uncertainties and that could potentially result in
materially different results under different assumptions and
conditions. For a detailed description of our accounting policies,
see our Annual Report on Form 10-K/A for the year ended
December 31, 2015.





Market Conditions





Prevailing prices
for the crude oil, natural gas and natural gas liquids
(“NGLs”) that we produce significantly impact our
revenues and cash flows. The benchmark prices for crude oil,
natural gas and NGLs were significantly lower in the first nine
months of 2016 compared to the same period in 2015; as a result, we
experienced significant declines in our price realizations
associated with those benchmarks. Additional detail on market
conditions, including our average price realizations and benchmarks
for crude oil, natural gas and NGLs relative to our operating
segments, follows.





Liquidity Considerations





As part of the closing of the Merger on October
26, 2016, Yuma Delaware entered into a new credit facility and the
outstanding balance under our credit facility was assumed in that
new credit facility by Yuma Delaware (“the Credit
Agreement”). The Credit Agreement provides for a $75.0
million 3-year revolving credit facility with SG Americas
Securities, LLC (“SG Americas”) as Lead Arranger and
Bookrunner, SocGen as Administrative Agent and the lenders party
thereto. The Credit Agreement replaces our existing credit
agreement. The initial borrowing base of the Credit Agreement is
$44.0 million, and is subject to redetermination as of January 1,
2017 as well as April 1st and October 1st of each year.
As of October 26, 2016, Yuma Delaware
had approximately $39.5 million outstanding under the Credit
Agreement. The incremental
$9.7 million of debt outstanding at October 26, 2016 under the new
Credit Agreement from the Company's outstanding debt balance of
$29.8 million at September 30, 2016 was primarily the result of
paying off Davis' outstanding debt balance of $9.0 million at Bank
of America, accrued interest under the old credit facilities, as
well as fees associated with the new Credit Agreement. All of the
obligations under the Credit Agreement, and the guarantee of those
obligations, are secured by substantially all of the assets of Yuma
Delaware and customary financial covenants have been
made.





28








Sales and Other Operating Revenues





The
following table presents the net quantities of crude oil, natural
gas and NGLs produced and sold by us for the three and nine months
ended September 30, 2016 and 2015, and the average sales price per
unit sold.





Three Months
Ended
September
30,
Nine Months
Ended
September
30,2016
2015
2016
2015Production
volumes:Crude oil and
condensate (Bbl)
47,079
61,938
155,986
186,531Natural gas
(Mcf)
340,189
497,868
1,148,587
1,488,408Natural gas liquids
(Bbl)
12,613
20,899
41,771
54,838Total
(Boe) (1)
116,390
165,815
389,188
489,437Average prices
realized:Excluding commodity
derivatives:Crude oil and
condensate (per Bbl)
$42.49
$46.10
$37.51
$50.52Natural gas (per
Mcf)
$2.72
$2.72
$2.28
$2.77Natural gas liquids
(per Bbl)
$17.94
$18.61
$17.71
$19.20Including commodity
derivatives:Crude oil and
condensate (per Bbl)
$53.46
$51.41
$49.24
$66.25Natural gas (per
Mcf)
$2.64
$2.93
$2.61
$4.24Natural gas liquids
(per Bbl)
$17.94
$18.61
$17.71
$19.20





(1)
 Barrels of oil
equivalent have been calculated on the basis of six thousand cubic
feet (Mcf) of natural gas equal to one barrel of oil equivalent
(Boe).





The
following table presents our revenues for the three and nine months
ended September 30, 2016 and 2015.





Three Months
Ended
September
30,
Nine Months
Ended
September
30,2016
2015
2016
2015Sales of natural
gas and crude oil:Crude oil and
condensate
$2,000,373
$2,855,530
$5,851,235
$9,423,519Natural
gas
924,994
1,340,877
2,616,440
4,112,065Natural gas
liquids
226,259
388,966
739,961
1,053,076Realized gain
(loss) on commodity derivatives
488,409
432,824
2,205,216
5,114,609Unrealized gain
(loss) on commodity derivatives
(40,473)
3,460,825
(2,613,044)
(1,847,371)Gas marketing
sales
-
63,637
-
167,923Total
revenues
$3,599,562
$8,542,659
$8,799,808
$18,023,821





Sale of Crude Oil and Condensate





Crude
oil and condensate are sold through month-to-month evergreen
contracts. The price for Louisiana production is tied to an index
or a weighted monthly average of posted prices with certain
adjustments for gravity, Basic Sediment and Water
(“BS&W”) and transportation. Generally, the index
or posting is based on West Texas Intermediate (“WTI”)
and adjusted to Light Louisiana Sweet (“LLS”) or Heavy
Louisiana Sweet (“HLS”). Pricing for our California
properties is based on an average of specified posted prices,
adjusted for gravity, transportation, and for one field, a market
differential.





Crude
oil volumes sold were 24.0% lower for the three months ended
September 30, 2016 than the crude oil volumes sold during the same
period in 2015. This decrease was a result of reduced production
levels at Bayou Hebert field due to facility maintenance as well as
downtime due to flooding in the area. In addition, the Livingston
field experienced reduced production due to flooding, and Main Pass
2 was affected by salt water disposal restrictions. Production in
Bayou Hebert field, Livingston field and Main Pass 2 has been
restored to normal levels. Realized crude oil prices decreased 7.8%
from the three months ended September 30, 2015 compared to the
three months ended September 30, 2016.


29








For the
nine months ended September 30, 2016, crude oil volumes sold were
16.4% lower than the same period in 2015. This decrease was the
result of shut-in wells in both operated and non-operated wells in
the Greater Masters Creek Field and the reasons listed above for
the three months ended September 30, 2016. It is not anticipated
that production will be restored from the operated and non-operated
Greater Masters Creek Field wells due to low commodity prices.
Realized crude oil prices were 25.8% lower for the nine months
ended September 30, 2016 compared to the same period in
2015.





Sale of Natural Gas and Natural Gas Liquids





Our
natural gas is sold under multi-year contracts with pricing tied to
either first of the month index or a monthly weighted average of
purchaser prices received. NGLs are also sold under multi-year
contracts usually tied to the related natural gas contract. Pricing
is based on published prices for each product or a monthly weighted
average of purchaser prices received.





For the
three months ended September 30, 2016 compared to the same period
in 2015, we experienced a 31.7% decrease in natural gas volumes
sold and a 39.6% decrease in NGLs sold primarily due to reduced
production levels at Bayou Hebert field due to facility maintenance
as well as downtime due to flooding in the area, and partially
offset by production from the Talbot 23-1 recompletion to Marg Tex
1 that happened late in the quarter. Production in Bayou Hebert
field has been restored to previous levels and the Talbot 23-1 well
continues to produce from the Marg Tex 1 zone at expected levels.
During the same period, realized natural gas prices did not change
and realized prices for NGLs decreased by 3.6%.





For the
nine months ended September 30, 2016, natural gas volumes sold
decreased by 22.8% and volumes of NGLs sold decreased by 23.8%
compared to the same period in 2015. This decrease was due
primarily to the reasons stated above for the three months ended
September 30, 2016, natural declines in production from other gas
wells, and additional down time at Bayou Hebert field while
restoring salt water disposal capacity. During the same period,
realized natural gas prices decreased by 17.7% and realized prices
for NGLs decreased by 7.8%.





Gas Marketing





Gas
marketing sales are natural gas volumes purchased from certain of
our operated wells and the aggregated volumes sold with a mark-up
of $.03 per MMBtu. Our wholly owned subsidiary, Texas Southeastern
Gas Marketing Company (“Marketing”), purchased and sold
natural gas on our behalf and on behalf of our working interest
partners. In early 2016, we discontinued Marketing due to a lack of
volumes and the associated costs of running the company (see Item
1. Unaudited Condensed Notes to the Consolidated Financial
Statements, Note 14 – Texas Southeastern Gas Marketing
Company).


30





Lease
Operating Expenses





Our
lease operating expenses (“LOE”) and LOE per Boe for
the three and nine months ended September 30, 2016 and 2015, are
set forth below:





Three Months
Ended
September
30,
Nine Months
Ended
September
30,2016
2015
2016
2015Lease operating
expenses
$1,178,134
$1,816,325
$3,757,500
$6,254,493Severance, ad
valorem taxes and marketing
620,734
902,594
1,934,577
2,913,767Total
LOE
$1,798,868
$2,718,919
$5,692,077
$9,168,260LOE per
Boe
$15.46
$16.40
$14.63
$18.73LOE per Boe without
severance, ad valorem taxes and marketing
$10.12
$10.95
$9.65
$12.78





LOE
includes all costs incurred to operate wells and related
facilities, both operated and non-operated. In addition to direct
operating costs such as labor, repairs and maintenance, equipment
rentals, materials and supplies, fuel and chemicals, LOE also
includes severance taxes, product marketing and transportation
fees, insurance, ad valorem taxes and operating agreement allocable
overhead. LOE excludes costs classified as re-engineering and
workovers.





The
33.8% decrease in total LOE for the three months ended September
30, 2016 compared to the same period in 2015 was primarily due to
our continued operating cost reduction initiatives implemented in
our Greater Masters Creek Field, Main Pass 2 and 4, and California.
LOE per Boe decreased by 5.7% for the same period generally due to
enhancement projects that kept production stable and the cost
reduction programs mentioned above.





For the
nine months ended September 30, 2016, total LOE decreased by 37.9%
compared to the same period in 2015, due primarily to the reasons
state above for the three months ended September 30, 2016 which led
to a decrease in LOE per Boe of 21.9% for the same
period.





Re-engineering and Workovers





Re-engineering and
workover expenses include the costs to restore or enhance
production in current producing zones as well as costs of
significant non-recurring operations.





Workover expenses
for the three months ended September 30, 2016 and 2015 totaled
$132,708 and $1,136, respectively. Workover expenses were incurred
in the third quarter of 2016 to repair salt water disposal
restrictions at Main Pass 2 and to repair artificial lift in
Livingston field. All the 2015 re-engineered facilities upgrades
and artificial lift optimization projects in our operated fields
continue to reduce the number of workovers, down time, and
nonrecurring operations overall. LOE per Boe, including
re-engineering and workovers, for the three months ended September
30, 2016 and 2015 totaled $16.60 and $16.40, respectively, a 1.2%
increase.





For the
nine months ended September 30, 2016 and 2015, workover expenses
totaled $132,708 and $555,628, respectively. High workover expenses
were incurred in the first half of 2015 to restore facilities and
salt water disposal at Main Pass 4 and artificial lift in
Livingston Field. LOE per Boe, including re-engineering and
workovers, for the nine months ended September 30, 2016 and 2015
totaled $14.97 and $19.87, respectively, a 24.7%
decrease.





31








General and Administrative Expenses





Our
general and administrative (“G&A”) expenses for the
three and nine months ended September 30, 2016 and 2015 are
summarized as follows:





Three Months
Ended
September
30,
Nine Months
Ended
September
30,2016
2015
2016
2015General and
administrativeStock-based
compensation
$196,561
$385,712
$943,127
$2,958,952Capitalized
stock-based comp
(7,350)
(47,093)
(33,818)
(748,002)Net
stock-based compensation
189,211
338,619
909,309
2,210,950Other
G&A
1,981,792
2,431,148
7,000,903
7,218,426Capitalized other
G&A
(400,173)
(557,664)
(1,258,079)
(1,828,567)Net
other G&A
1,581,619
1,873,484
5,742,824
5,389,859Net general and
administrative
$1,770,830
$2,212,103
$6,652,133
$7,600,809





G&A
expenses primarily consist of overhead expenses, employee
remuneration and professional and consulting fees. We capitalize
certain G&A expenditures when they satisfy the criteria for
capitalization under GAAP as relating to oil and natural gas
exploration activities following the full cost method of
accounting.





For the
three months ended September 30, 2016, G&A expenses inclusive
of amounts capitalized were $638,507 (22.7%) lower than the amount
for the same period in 2015. This decrease in G&A expenses was
primarily attributed to a $290,200 decrease in salary expenses due
to a 21.4% staff reduction, a $189,151 decrease in stock-based
compensation, a $168,354 decrease in consulting fees, a $70,939
decrease in audit and accounting fees, offset by $176,871 in
increased non-recurring professional costs associated with the
Davis merger during 2016. .





For the
nine months ended September 30, 2016, G&A expenses inclusive of
amounts capitalized were $2,233,348 (21.9%) lower than the same
period in 2015. Costs for the Davis merger of $1,046,652 increased
G&A costs for the current nine-month period; however, this
increase was offset by a $1,872,173 decrease in stock-based
compensation, a $596,094 decrease in salaries due to staff
reductions, and a $453,312 decrease in consulting
fees.





Depreciation, Depletion and Amortization





Our
depreciation, depletion and amortization (“DD&A”)
and DD&A per Boe for the three and nine months ended September
30, 2016 and 2015 is summarized as follows:





Three Months
Ended
September
30,
Nine Months
Ended
September
30,2016
2015
2016
2015Depreciation,
Depletion and Amortization
$1,711,043
$3,123,812
$6,178,248
$11,020,278DD&A per
Boe
$14.70
$18.84
$15.87
$22.52





DD&A per Boe
decreased by 22.0% and 29.5% for the three and nine months ended
September 30, 2016 compared to the same periods in 2015. Decreases
in 2016 production compared to 2015 caused corresponding decreases
to depletion (see preceding Sales discussion for production
detail). In addition, future development costs, a component of the
depletion base, are down from the September 30, 2015 projection.
Depressed commodity prices are the primary cause for the reduction
in projected future development costs.


32








Interest Expense





Our
interest expense for the three and nine months ended September 30,
2016 and 2015 is summarized as follows:





Three Months
Ended
September
30,
Nine Months
Ended
September
30,2016
2015
2016
2015Interest
expense
$387,290
$398,063
$1,369,647
$1,087,606Interest
capitalized
(141,931)
(266,949)
(395,244)
(750,107)Net
$245,359
$131,114
$974,403
$337,499Bank
debt
$29,800,000
$29,700,000
$29,800,000
$29,700,000





Gross
interest expense decreased $10,773 for the three months ended
September 30, 2016 and increased $282,041 for the nine months ended
September 30, 2016 over the same periods in 2015. The increased
amortization of debt costs related to the acceleration of the
maturity dates under our credit facility pursuant to the Ninth and
Tenth Amendments increased interest expense in the first nine
months of 2016 as compared to 2015 by $308,576. Capitalized
interest decreased $125,018 and $354,863 for the three and nine
months ended September 30, 2016 from the same periods in 2015,
driven by a decrease in our unevaluated properties, which is the
basis of our capitalized interest calculation.





Income Tax Expense





We
recorded an income tax benefit of $1,272,664 on a pre-tax net loss
of $22,135,882 resulting in an effective tax rate of 5.7% for the
nine months ended September 30, 2016. For the nine months ended
September 30, 2015, we recorded an income tax benefit of $3,605,839
on a pre-tax loss of $16,928,915, resulting in an effective tax
rate of 21.3%.





Differences between
the U.S. federal statutory rate of 34% and our effective tax rates
are due primarily to state taxes and nondeductible expenses. In
addition, September 30, 2016 was impacted by the expected valuation
allowance on our deferred tax asset at year-end, which affected our
expected annual effective tax rate and the tax effect of
nondeductible stock compensation.





Liquidity and Capital Resources





Cash Flows





The
change in our cash for the nine months ended September 30, 2016 and
2015 is summarized as follows:





Nine Months
Ended
September
30,2016
2015Cash flows provided
by (used in) operating activities
$(804,695)
$(4,280,324)Cash flows used in
investing activities
(2,247,852)
(10,010,324)Cash flows provided
by (used in) financing activities
(470,716)
7,780,430Net increase
(decrease) in cash
$(3,523,263)
$(6,510,218)





Cash Flows from Operating Activities





Cash
flows from operations for the nine months ended September 30, 2016
increased by $3,475,629, or 81.2%, over the same period in 2015
primarily due to changes in working capital and decreases in lease
operating expenses, somewhat offset by lower revenue from decreased
production and lower commodity prices as mentioned
earlier.


33








Cash Flows from Investing Activities





Oil and
natural gas investing activities decreased by $7,762,472 or 77.5%
in the nine months ended September 30, 2016 compared to the same
period in 2015. The decrease was primarily due to a reduction in
capital expenditures in 2016 compared to 2015.





During
the nine months ended September 30, 2016, we invested $2,588,455 in
lease acquisition costs and capital expenditures related to a
recompletion, workovers, P&A activity and software.  Lease
acquisition costs primarily included capitalized G&A and
capitalized interest associated with the North Austin Chalk and Cat
Canyon prospects.   Notable projects include the DS&B
121 well recompletion for a cost of $166,935, Starns 38 #1 ESP
installation with costs of $70,726, P&A costs of $309,052 for
four Crosby SWD wells and the McRight 11 #1, as well as the removal
of various Greater Masters Creek Field facilities totaling
$76,496.  We had six property sales during the period ended
September 30, 2016 resulting in $340,603 in net
proceeds.





During
the nine months ended September 30, 2015, the Amazon 3-D Project
accounted for $3,964,620 of our total oil and natural gas investing
activities. Of that, $3,682,212 was spent on the drilling of the
Talbot 23-1 well and related Anaconda prospect costs. At the
Greater Masters Creek Field, $1,672,681 was spent primarily on the
workover of the Bullock A-1 and the completion of the Crosby 14-1
and its salt water disposal well. At the Livingston 3-D Project,
$1,377,842 was spent, with most of the expenditures going to the
completion of the Blackwell 39-1 well and related Musial prospect
costs, along with capital workovers to add electric submersible
pumps to two wells.





Cash Flows from Financing Activities





Our
cash flows, both in the short-term and the long-term, are impacted
by highly volatile oil and natural gas prices. Although we seek to
mitigate this risk by hedging future crude oil and natural gas
production, a significant deterioration in commodity prices
negatively impacts revenues, earnings, and cash flows, capital
spending, and potentially our liquidity. Sales volumes and costs
also impact cash flows; however, these historically have not been
as volatile or as impactful as commodity prices in the
short-term.





We
expect to finance future acquisition, development and exploration
activities through available working capital, cash flows from
operating activities, advances from our credit facility, sale of
non-strategic assets, increased liquidity from the merger with
Davis, and/or the possible issuance of additional equity/debt
securities. In addition, we may slow or accelerate our development
of existing reserves to more closely match our projected cash
flows.





At
September 30, 2016, we had a $29.8 million borrowing base with
$29.8 million advanced, leaving no available borrowing capacity.
See Credit Facility section below.





Nine Months
Ended
Year
EndedSeptember 30,
2016
December 31,
2015Credit
Facility:Balances
outstanding, beginning of year
$29,800,000
$22,900,000Activity
-
6,900,000Balances
outstanding, end of period
$29,800,000
$29,800,000





34





Other
than the credit facility, we had debt of $0 and $263,635 at
September 30, 2016 and December 31, 2015, respectively, from
installment loans financing oil and natural gas property insurance
premiums. We had a cash balance of $1,831,928 at September 30,
2016.





Credit Facility





Upon the closing of the Merger
discussed in Item 1. Unaudited Condensed Notes to the Consolidated
Financial Statements, Note 15 – Subsequent Events, the entire
outstanding balance under the credit facility was assumed by Yuma
Delaware in a new credit facility (“the Credit
Agreement”). The Credit Agreement provides for a $75.0
million 3-year revolving credit facility with SG Americas
Securities, LLC (“SG Americas”) as Lead Arranger and
Bookrunner, SocGen as Administrative Agent and the lenders party
thereto. The Credit Agreement replaces our existing credit
agreement. The initial borrowing base of the Credit Agreement is
$44.0 million, and is subject to redetermination as of January 1,
2017 as well as April 1st and October 1st of each year. As of
October 26, 2016, Yuma Delaware had approximately $39.5 million
outstanding under the Credit Agreement. The incremental $9.7 million of
debt outstanding at October 26, 2016 under the new Credit Agreement
from the Company's outstanding debt balance of $29.8 million at
September 30, 2016 was primarily the result of paying off Davis'
outstanding debt balance of $9.0 million at Bank of America,
accrued interest under the old credit facilities, as well as fees
associated with the new Credit Agreement. All of the obligations
under the Credit Agreement, and the guarantee of those obligations,
are secured by substantially all of the assets of Yuma Delaware and
customary financial covenants have been
made.





Hedging Activities





Current Commodity Derivative Contracts





We seek
to reduce our sensitivity to oil and gas price volatility and
secure favorable debt financing terms by entering into commodity
derivative transactions which may include fixed price swaps, price
collars, puts, calls and other derivatives. We believe our hedging
strategy should result in greater predictability of internally
generated funds, which in turn can be dedicated to capital
development projects and corporate obligations.





Fair Market Value of Commodity Derivatives





September 30,
2016
December 31,
2015Oil
Gas
Oil
GasAssetsCurrent
$1,016,583
$-
$2,393,032
$265,015Noncurrent
177,724
-
1,049,661
20,880LiabilitiesCurrent
$-
$(74,331)
$-
$-Noncurrent
-
(4,432)
-
-





Assets
and liabilities are netted within each commodity on the
Consolidated Balance Sheets as all contracts are with the same
counterparty. For the balances without netting, refer to Item 1.
Unaudited Condensed Notes to the Consolidated Financial Statements,
Note 5 – Commodity Derivative Instruments.





The
fair market value of our commodity derivative contracts in place at
September 30, 2016 and December 31, 2015 were net assets of
$1,115,544 and $3,728,588, respectively. Please see Item 1.
Unaudited Condensed Notes to the Consolidated Financial Statements,
Note 5 – Commodity Derivative Instruments, for
additional information on our commodity derivatives.


35








Commitments and Contingencies





We had
the following contractual obligations and commitments as of
September 30, 2016:





Debt
(1)
Commodity
Derivatives
(2)
Operating
Leases
Asset
Retirement
Obligations2016
$29,800,000
$301,930
$146,060
$243,7112017
-
813,614
564,732
111,6202018
-
-
2,264
3,718,1302019
-
-
-
2,164,7142020
-
-
-
208,427Thereafter
-
-
-
2,369,004Totals
$29,800,000
$1,115,544
$713,056
$8,815,606





(1)
Does
not include future commitment, modification or covenant waiver
fees, interest expense or other expenses or costs because the
credit agreement is a floating rate instrument, and we cannot
determine with accuracy the timing of future loans, advances,
modifications, repayments or future interest rates to be
charged.





(2)
Represents
the estimated future receipts under our oil and natural gas
derivative contracts based on the future market prices as of
September 30, 2016. These amounts will change as oil and natural
gas commodity prices change.





Off Balance Sheet Arrangements





We do
not have any off balance sheet arrangements, special purpose
entities, financing partnerships or guarantees (other than our
guarantee of our wholly owned subsidiary’s credit
facility).





Item
3. Quantitative and Qualitative Disclosures about Market
Risk.





We are
a smaller reporting company as defined by Rule 12b-2 of the
Exchange Act and are not required to provide the information under
this Item.





Item 4. Controls and Procedures.





Evaluation of disclosure controls and procedures.





We
maintain disclosure controls and procedures that are designed to
ensure that information required to be disclosed in our Exchange
Act reports is accurately recorded, processed, summarized and
reported within the time periods specified in the SEC’s
rules and forms, and that such information is accumulated and
communicated to our management, including our Chief Executive
Officer and Chief Financial Officer, as appropriate, to allow
timely decisions regarding required disclosure.  In designing
and evaluating the disclosure controls and procedures, management
recognizes that any controls and procedures, no matter how well
designed and operated, can provide only reasonable assurance of
achieving the desired control objectives, and management
necessarily applied its judgment in evaluating the cost-benefit
relationship of possible controls and procedures.





As of
September 30, 2016, we carried out an evaluation, under the
supervision and with the participation of our management, including
our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of the design and operation of our disclosure
controls and procedures (as defined in Exchange Act
Rules 13a-15(e) and 15d-15(e)).  Based on that
evaluation, our Chief Executive Officer and Chief Financial Officer
concluded that our disclosure controls and procedures were not
effective as of September 30, 2016. Specifically, we did not
have appropriate policies and procedures in place to properly
evaluate the accuracy of certain of our financial accounts as more
particularly described in our annual report on Form 10-K/A filed
with the SEC on May 23, 2016.


36








Changes in internal control over financial
reporting.





During
the three month period ended September 30, 2016, there were no
changes in our internal control over financial reporting (as
defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), except for
the changes described in the Remedial Action section below, that
have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.





Remedial Action





We
began our remediation plan in the second quarter of 2016 with
respect to improving our internal control over financial reporting
to address the material weakness(es) that were disclosed in our
annual report on Form 10-K/A filed with the SEC on May 23, 2016.
Specifically as it relates to the presentation and accounting for
our income taxes, we hired an internationally known accounting firm
as our new tax consultants to assist management with its
preparation of these items, and hired additional accounting
personnel in the fourth quarter of 2016. Additionally, we have
implemented a more robust review, and increased the supervision and
monitoring of the financial reporting processes related to the
preparation of our income tax provisions. We implemented these
procedures in the second quarter of 2016, but believe that we
require sufficient testing of these newly established procedures
and controls prior to declaring that we have effective disclosure
controls and procedures.





PART II. OTHER INFORMATION





Item 1. Legal Proceedings.





A
description of our legal proceedings is included in Item 1.
Unaudited Condensed Notes to the Consolidated Financial Statements,
Note 12 – Contingencies, and is incorporated herein by
reference.





From
time to time, we may be a plaintiff or defendant in a pending or
threatened legal proceeding arising in the normal course of our
business. While the outcome and impact of currently pending legal
proceedings cannot be determined, our management and legal counsel
believe that the resolution of these proceedings through settlement
or adverse judgment will not have a material effect on our
consolidated operating results, financial position or cash
flows.





Item 1A. Risk Factors.





In
addition to the other information set forth in this report, you
should carefully consider the factors discussed in Part I,
“Item 1A – Risk Factors” in our Annual Report for
the year ended December 31, 2015 on Form 10-K/A, which could
materially affect our business, financial condition or future
results. The risks described in our 2015 Annual Report on Form
10-K/A may not be the only risks facing our Company. There are no
updates to our risk factors as disclosed in our Annual Report on
Form 10-K/A for the year ended December 31, 2015. Additional risks
and uncertainties not currently known to us or that we currently
deem to be immaterial may materially adversely affect our business,
financial condition and/or operating results.





37








Item
2.  Unregistered Sales of Equity Securities and Use of
Proceeds.





The following
table sets forth information regarding our acquisition of shares of
common stock for the periods presented (adjusted for the 1-for-20
reverse stock split as described in Item 1. Unaudited Condensed
Notes to the Consolidated Financial Statements, Note 15 –
Subsequent Events).





Total Number of
Shares Purchased(1)
Average Price
Paid Per Share
Total Number of
Shares Purchased as Part of Publicly Announced Plans or
Programs
Maximum Number
(or Approximate Dollar Value) of Shares that May Yet Be Purchased
Under the Plans or ProgramsJuly
2016
951
$5.51
-
-August
2016
-
-
-
-September
2016
-
-
-
-





(1) All
of the shares were surrendered by employees in satisfaction of tax
obligations upon the vesting of restricted stock awards. The
acquisition of the surrendered shares was not part of a publicly
announced program to repurchase shares of our common stock, nor
were they considered as or accounted for as treasury
shares.





Item
3.  Defaults upon Senior Securities.





We were
in violation of three of the financial covenants under our credit
facility at September 30, 2016. Under the new credit facility,
which was entered into in connection with the Merger, Yuma Delaware
is in compliance with the credit facility. This new credit facility
supersedes the Company’s previous credit agreement and
non-compliance matters discussed above. See Item 1. Unaudited
Condensed Notes to the Consolidated Financial Statements, Note 2
– Liquidity Considerations.


Effective November
1, 2015, we suspended the payment of dividends on the Series A
Preferred Stock until such time as our Board believes the Company
has adequate liquidity to restore the payment of the
dividends.





Item
4.  Mine Safety Disclosure.





Not
Applicable.





Item
5.  Other Information.





None.





38





Item
6.   Exhibits.





EXHIBIT
INDEX


FOR





Form 10-Q for the quarter ended September 30, 2016.Incorporated by
ReferenceExhibit
No.

Description

Form

SEC File
No.

Exhibit

Filing
Date

Filed
Herewith

Furnished
Herewith2.1

Agreement
and Plan of Merger and Reorganization dated as of February 10,
2016, by and among Yuma Energy, Inc., Yuma Delaware Merger
Subsidiary, Inc., Yuma Merger Subsidiary, Inc. and Davis Petroleum
Acquisition Corp.

8-K/A

001-32989

2.1

February
16, 20162.1(a)

First
Amendment to the Agreement and Plan of Merger and Reorganization
dated as of September 2, 2016, by and among Yuma Energy, Inc., Yuma
Delaware Merger Subsidiary, Inc., Yuma Merger Subsidiary, Inc. and
Davis Petroleum Acquisition Corp.

8-K

001-32989

2.1

September
6, 201631.1

Certification
of the Principal Executive Officer pursuant to Section 302 of the
Sarbanes-Oxley Act.









X31.2

Certification
of the Principal Financial Officer pursuant to Section 302 of the
Sarbanes-Oxley Act.









X32.1

Certification
of the Chief Executive Officer pursuant to Section 906 of the
Sarbanes-Oxley Act.











X32.2

Certification
of the Chief Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act.











X101.INS

XBRL
Instance Document.









X101.SCH

XBRL
Schema Document.









X101.CAL

XBRL
Calculation Linkbase Document.









X101.DEF

XBRL
Definition Linkbase Document.









X101.LAB

XBRL
Label Linkbase Document.









X101.PRE

XBRL
Presentation Linkbase Document.









X











39





SIGNATURES








Pursuant to the
requirements of the Securities Exchange Act of 1934, the Registrant
has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.








YUMA ENERGY, INC.By:
/s/ Sam
L. BanksName:
Sam L.
BanksDate:
November 14, 2016

Title:
President
and Chief Executive Officer
(Principal
Executive Officer)By:
/s/
James J. JacobsDate:
November 14, 2016

Name:
James
J. JacobsTitle:
Chief
Financial Officer (Principal Financial Officer)








40