HOUSTON, TX--(Marketwired - Nov 14, 2014) - Yuma Energy, Inc. (NYSE MKT: YUMA) (the "Company" or "Yuma") today announced its financial results for the quarter and nine months ended September 30, 2014 and provided an operational overview relating to its properties.

Third Quarter 2014 Highlights

  • Production averaged 1,646 Boe/d compared to 1,377 Boe/d for the three months ended September 30, 2013, a 19.5% increase.

  • Revenues totaled $10.6 million compared to $6.2 million for the three months ended September 30, 2013, a 70.0% increase, which includes an approximately $2.4 million net gain in commodity derivatives (i.e. hedges).

  • Ended the quarter with approximately $30.3 million in Liquidity (1) (non-GAAP).

  • The Company successfully drilled and completed the Nettles 39-1 well in Livingston Parish, Louisiana where we hold a 32.5% working interest. The well was placed on production on September 5, 2014 and averaged approximately 125 Bbl/d of oil in September. The well has since cleaned up and averaged approximately 250 Bbl/d of oil during the first 10 days of November. 

  • Ended the quarter with positive hedges in place through 2016 for both oil and gas.(2)

(1) See description in section titled "Liquidity and Capital Resources" in this release.
(2) See Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note C - Commodity Derivative Instruments in our Form 10-Q for the period ended September 30, 2014.

Nine Months Ended September 30, 2014 Highlights

  • Production averaged 2,270 Boe/d compared to 1,110 Boe/d for the same period in 2013, representing a 104.5% increase.

  • Crude oil revenues were approximately $17.5 million, an increase of 26.5% compared to the same period in 2013.

  • Natural gas revenues were approximately $10.6 million, an increase of 200.5% compared to the nine months ended September 30, 2013.

Operational Overview

La Posada - Bayou Hebert Field, Vermilion Parish, Louisiana. We have a 12.5% working interest in La Posada. We initially generated the exploration prospect by utilizing data from a 3-D seismic survey, which resulted in a significant discovery. The primary objectives were the Lower Planulina Cris R sands, at a depth of approximately 17,700 to 18,250 feet.

The prospect was successfully tested in 2011 on the southern portion of the structure by the operator PetroQuest Energy, Inc. A brief summary of the drilling activity to date is as follows:

1. The Thibodeaux No. 1 well was drilled to a total depth of 19,079 feet and logged a net 217 feet of hydrocarbon bearing sand. The well was put on production in March 2012.

2. The Broussard No. 2 well was drilled to a depth of 19,150 feet on the north side of the structure in 2012. This well logged a net 328 feet of hydrocarbon bearing sand in the Lower Planulina Cris R-1 and Cris R-2A, B and C sandstones. The well was put on production in September 2012.

3. The Broussard No. 1 well (originally drilled and temporarily abandoned in 2007) was re-entered and sidetracked to the upper Cris R sand as an acceleration well. The Broussard No. 1 sidetrack was drilled to a depth of 18,035 feet and encountered the upper productive sand in 2013. The well was put on production in May 2013.

During the first half of 2014, the Bayou Hebert Field produced at an average rate of 106 MMcf/d of natural gas, and 1,900 Bbl/d of oil. In July 2014, the Broussard No. 2 experienced an increase in water production. Although the natural gas production from the well was not affected by the increase in water, both the Broussard No. 2 and the Thibodeaux No. 1 were curtailed to avoid exceeding the water handling capability of the production facilities. Field production decreased to 45 MMcf/d of natural gas and 850 Bbl/d of oil which decreased our revenues and production for the three months ended September 30, 2014. 

In September 2014, the operator reconfigured the production facilities and increased the production to approximately 53 MMcf/d of natural gas and 1,000 Bbl/d of oil. The operator has also ordered higher capacity water handling equipment that is expected to be installed in November 2014. With the installation of this additional equipment, we anticipate the field will produce between 70 MMcf/d and 75 MMcf/d of natural gas and 1,500 Bbl/d of oil starting in the fourth quarter of 2014. We also expect that during 2015, the Thibodeaux No. 1 will be recompleted from its current "C" zone to the overlying "B" zone, after which the total production from the field is expected to increase to between 95 MMcf/d and 105 MMcf/d of natural gas and 1,700 Bbl/d to 1,900 Bbl/d of oil.

Livingston Prospects, Livingston Parish, Louisiana.  Our primary exploration targets which produce in the area include intermediate depth Wilcox sands and the deeper lower Tuscaloosa sands. We hold an average 33% working interest across the Livingston prospects and are the operator. 

To date we have drilled five exploration wells with four discoveries on our Livingston project. Three of the wells targeted the lower Tuscaloosa sands (oil), two of which were discoveries, one well targeted the Wilcox formation (oil), and one well drilled for a shallow Miocene target (gas). The shallow Miocene well has produced out and has been shut in. 

We drilled two development wells offsetting our Lower Tuscaloosa discoveries in addition to one development well offsetting our Wilcox discovery. Currently, three wells are producing from the lower Tuscaloosa sands and two wells are producing from the Wilcox. One of the Tuscaloosa wells, the Weyerhaeuser 9-1, is currently shut-in due to high water production and is being evaluated for a workover in the fourth quarter of 2014. Also, during the three months ended September 30, 2014, we had to temporarily shut in one of our Lower Tuscaloosa wells, the Weyerhaeuser 57-3, due to pumping equipment failure. The average daily production from the five remaining wells during the three months ended September 30, 2014 was 376 Boe/d gross (85 Boe/d net). 

We drilled our first Wilcox discovery in 2013, the Starns 38-1, to a depth of 10,000 feet. The Starns 38-1 has produced more than 50,000 Bbls of oil and flowed between 100 Bbl/d and 115 Bbl/d during the three months ended September 30, 2014. We recently drilled the Nettles 39-1, an eastern offset to the Starns 38-1. The well was placed on production on September 5, 2014 and averaged approximately 125 Bbl/d of oil in September. The well has since cleaned up and averaged approximately 250 Bbl/d of oil during the first 10 days in November. 

Plans are being made to drill the third well in this Wilcox discovery, the Blackwell 39-1. This will be an eastern offset to the Nettles 39-1, and we anticipate drilling to a depth of 10,000 feet in this Wilcox test. We plan to spud the well during the beginning of the first quarter of 2015 and, if successful, we intend to have it on production during the first quarter of 2015. Our working interest is 32.5% in each of the Starns 38-1, Nettles 39-1 and the Blackwell 39-1 wells.

In addition, we plan to drill a lower Tuscaloosa prospect, the Glacier prospect, in the Livingston 3-D seismic survey area in the first half of 2015.

Lake Fortuna Field (Raccoon Island), St. Bernard Parish, Louisiana. We discovered our Lake Fortuna field in 1996 when our 3-D Raccoon Island prospect was drilled. The target was a Middle Miocene sand on a known productive structure. In 2005, we acquired the majority of the working interest in Raccoon Island from Amerada Hess, and now own a working interest of 91%. During the three months ended September 30, 2014 we temporarily shut in a portion of the field to repair a salt water disposal well. This shut-in affected our third quarter 2014 production and revenues, but production in the field was restored to previous levels (approximately 250 Bbl/d of oil gross) after the work-over was performed. 

Greater Masters Creek Field, Allen, Vernon, Rapides and Beauregard Parishes, Louisiana. Our Greater Masters Creek Field properties are located in the Austin Chalk Trend in west central Louisiana. At December 31, 2013 we held approximately 76,178 net acres in the field. The acreage is located within an existing field which has previously been developed. Based on our technical analysis and independent third-party engineering, we believe there are approximately 70 operated proved undeveloped locations and 14 non-operated proved developed locations that are either held by production or leases. 

We recently completed our second operated Austin Chalk well, the Crosby 14-1, which was drilled vertically to approximately 15,000 feet to the top of the Austin Chalk formation and then 3,100 feet horizontally in the Austin Chalk formation. We expect to have the well on production in approximately 30 to 45 days and hold an approximate 61% working interest in the well. We expect to spud our third Austin Chalk well in the field in 2015. 

Amazon 3-D Project, Calcasieu and Jefferson Parishes, Louisiana. In 2011, we shot a 70 square mile 3-D seismic survey targeting the Frio (Hackberry and Marg Tex/Cib Haz/Camerina objectives). The Hackberry is a "bright spot" play for natural gas with rich condensate yields found in stratigraphic traps at depths of approximately 13,000 feet. The Marg Tex/Cib Haz/Camerina objectives are found at depths typically around 9,000 feet in structural traps independent of the underlying Hackberry.

We plan to drill our Anaconda prospect in the first quarter of 2015. This single well prospect is unique in that it has both Hackberry and Marg Tex objectives. The Hackberry exhibits a "bright spot" on the 3-D seismic, the attributes of which are very similar to Hackberry discoveries drilled by other operators within a mile of our location. At the Marg Tex interval, the well is anticipated to intersect four Marg Tex sands.

Cat Canyon Field, Santa Barbara, California. Our Cat Canyon field is a legacy asset that was owned by Pyramid Oil Company, prior to our merger completed on September 10, 2014. The field produces from the Monterey formation and is found at a depth of 4,500 feet and is nearly 2,000 feet thick. We have a 100% working interest in 120 acres held by production in this field. The field is surrounded by Monterey wells drilled from the late 1940's through 1982 on 10 acre spacing. The wells are drilled vertically, completed naturally (without fracing) and are put on pump immediately. We plan to drill our first operated well on this property in the first half of 2015.

Bakken - Yellowstone and Southeast Homerun. At December 31, 2013, we held an average 5% non-operated working interest in 18,513 gross acres (965 net acres) in McKenzie County, North Dakota. We have interests in six producing oil wells and two active salt water disposal wells. All producing wells are located in two fields, Yellowstone and Southeast Homerun. The majority of our interests are currently operated by Zavanna, LLC. We currently estimate that approximately 140 drilling locations remain across our Bakken asset. In addition, we believe significant future infill and Three Forks development upside potential exists on our acreage. 

Financial Results

Sales and Other Operating Revenues

The following table presents the net quantities of oil, natural gas and natural gas liquids produced and sold by us for each of the three and nine months ended September 30, 2014 and 2013, and the average sales price per unit sold.

         
    Three Months Ended September 30,   Nine Months Ended September 30,
    2014   2013   2014   2013
Production volumes:                        
  Crude oil and condensate (Bbl)     49,475     43,509     172,965     128,970
  Natural gas (Mcf)     513,002     433,967     2,229,405     903,959
  Natural gas liquids (Bbl)     16,457     10,865     77,389     23,519
    Total (Boe) (1)     151,432     126,702     621,922     303,149
                         
Average prices realized:                        
  Excluding commodity derivatives (both realizedand unrealized)                        
    Crude oil and condensate (per Bbl)   $ 98.58   $ 109.25   $ 101.23   $ 107.30
    Natural gas (per Mcf)   $ 4.04   $ 3.91   $ 4.76   $ 3.90
    Natural gas liquids (per Bbl)   $ 40.73   $ 41.72   $ 41.25   $ 42.64
  Including commodity derivatives (realized only)                        
    Crude oil and condensate (per Bbl)   $ 93.66   $ 101.57   $ 93.68   $ 104.99
    Natural gas (per Mcf)   $ 4.13   $ 4.38   $ 4.36   $ 4.13
    Natural gas liquids (per Bbl)   $ 40.73   $ 41.72   $ 41.25   $ 42.64
                             
(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 (1 Boe).
   
   

The following table presents our revenues for the three and nine months ended September 30, 2014 and 2013.

             
    Three Months Ended September 30,     Nine Months Ended September 30,  
    2014     2013     2014     2013  
Sales of natural gas and crude oil:                                
  Crude oil and condensate   $ 4,877,227     $ 4,753,431     $ 17,508,388     $ 13,838,521  
  Natural gas     2,074,901       1,696,623       10,606,760       3,529,837  
  Natural gas liquids     670,267       453,262       3,192,449       1,002,775  
  Realized gain/(loss) on commodity derivatives     (200,176 )     (130,286 )     (2,194,348 )     (94,228 )
  Unrealized gain/(loss) on commodity derivatives     2,607,959       (823,361 )     921,026       439,478  
  Gas marketing sales     199,102       (70,715 )     529,969       715,523  
                                 
Other revenue     341,819       308,092       885,455       739,584  
Total revenues   $ 10,571,099     $ 6,187,046     $ 31,449,699     $ 20,171,490  
                                 
                                 

NON-GAAP FINANCIAL MEASURES

Adjusted EBITDA

The following table reconciles reporting net income to EBITDA and Adjusted EBITDA for the periods indicated:

             
    Three Months Ended September 30,     Nine Months Ended September 30,  
    2014     2013     2014     2013  
Net Income   $ (11,152,037 )   $ 15,814,648     $ (18,997,712 )   $ (7,067,374 )
  Add: Depreciation, depletion & amortization of property and equipment     3,865,675       3,203,017       15,604,283       7,315,103  
  Add: Interest expense, net of interest income and amounts capitalized     112,078       62,009       316,850       482,564  
  Deduct: Income tax benefit     (576,632 )     (2,040,000 )     (1,710,632 )     (1,998,800 )
EBITDA     (7,750,916 )     17,039,674       (4,787,211 )     (1,268,507 )
                                 
  Add: Costs to obtain a public listing     844,482       -       2,729,447       -  
  Add (deduct): Increase (decrease) in value of preferred stock derivative liability     11,172,928       (15,382,964 )     15,676,842       7,581,234  
  Add: Accretion of asset retirement obligation     150,628       187,025       438,717       464,306  
  Add: Bank mandated commodity derivative novation cost     -       -       -       175,000  
  Deduct: Amortization of benefit from commodity derivatives sold     (23,438 )     (18,150 )     (70,313 )     (54,450 )
  Add (deduct): Net commodity derivatives mark-to-market loss (gain)     (2,607,959 )     823,361       (921,026 )     (439,478 )
Adjusted EBITDA   $ 1,785,725     $ 2,648,946     $ 13,066,456     $ 6,458,105  
                                 
                                 

"EBITDA" represents earnings before interest, taxes, depreciation, depletion and amortization, and is a non-GAAP financial measure. Because the Company makes other adjustments to its EBITDA formula by considering the change in the preferred stock derivative liability, accretion of asset retirement obligations, costs to obtain a public listing, and changes in commodity derivative values, we refer to this metric as Adjusted EBITDA and it is provided as an additional metric that is used by the Company's board of directors and management to measure operating performance and trends.

Adjusted EBITDA is presented based on management's belief that it will enable a user of the financial information to understand the impact of these items on reported results. Additionally, this presentation provides a helpful comparison to similarly adjusted measurements of prior periods. Adjusted EBITDA is not a measure of financial performance under GAAP and should not be considered as an alternative to net income, earnings per share and cash flow from operations, as defined by GAAP. Adjusted EBITDA may not be comparable to similarly named non-GAAP financial measures that other companies may use and may not be useful in comparing the performance of those companies to the Company's performance.

Liquidity and Capital Resources (1)

Liquidity is calculated by adding the net funds available under our credit facility to our cash and cash equivalents and short term investments. We use liquidity as an indicator, along with our ongoing cash flow, of our ability to satisfy our future capital expenditures. 

At September 30, 2014, we had a $40.0 million conforming borrowing base, with a $4.5 million additional non-conforming borrowing base, providing a total borrowing base of $44.5 million. At September 30, 2014, we had an undrawn amount of $19,535,000 under our credit facility.

In addition, we had a cash and cash equivalents balance of $9.6 million and short-term investments of $1.2 million at September 30, 2014 and $4.2 million in cash and cash equivalents at December 31, 2013. This resulted in Liquidity (1) of approximately $30.3 million for the quarter ended September 30, 2014. 

(1) Liquidity can vary from period to period for Yuma Energy, Inc. and can vary among companies as to what is or is not included in liquidity. This measurement should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not in accordance with, nor superior to, generally accepted accounting principles, but provides additional information for evaluation of our operating performance.

Management Comments

Sam L. Banks, Chairman, President and CEO of Yuma Energy, Inc. commented, "This is the first reporting period for Yuma since the closing of our merger with Pyramid Oil Company on September 10, 2014. While we made important strides to implement the integration of Yuma and Pyramid post-merger and preparation towards drilling of our significant inventory of oil and gas assets, this quarter's production was affected by temporary interruptions in production at our La Posada, Livingston and Raccoon Island projects. These interruptions were and are temporary in nature, and we believe that as we move forward you will see us moving back and above production levels seen in the second quarter of 2014. As we proceed forward we intend to further acquaint the market with our operations and capabilities and execute on our business strategy of transitioning existing proved undeveloped reserves and our 3-D prospect inventory into production. We have more than 30 years of successful exploration and production activities, with an emphasis on generating viable prospects and projects. For further information we invite readers to review our web page at www.yumaenergyinc.com, our recently filed quarterly report on Form 10-Q, as well as more comprehensive SEC filings that were made in connection with our merger with Pyramid." 

Mr. Banks further stated "While we are clearly focused on the effective execution and the near-term growth opportunities associated with our inventory of oil and gas assets, we will also continue to devote our considerable technical expertise to generate or acquire additional profitable projects moving forward."

Unaudited Financial Statements

   
Yuma Energy, Inc.  
   
CONSOLIDATED BALANCE SHEETS  
   
    September 30,
2014
(Unaudited)
   
December 31,
2013
 
ASSETS                
                 
CURRENT ASSETS:                
  Cash and cash equivalents   $ 9,562,262     $ 4,194,511  
  Short-term investments     1,154,281       -  
  Accounts receivable, net of allowance for doubtful accounts:                
    Trade     9,520,345       10,837,211  
    Stockholder and employees     85,870       155,080  
    Other     991,732       417,850  
  Commodity derivative instruments     383,603       -  
  Prepayments     789,083       433,991  
  Deferred taxes     -       146,964  
  Other deferred charges     304,120       162,416  
                 
      Total current assets     22,791,296       16,348,023  
                 
OIL AND GAS PROPERTIES (full cost method):                
  Not subject to amortization     38,463,577       24,051,278  
  Subject to amortization     166,776,420       152,863,988  
                 
      205,239,997       176,915,266  
    Less: accumulated depreciation, depletion and amortization     (99,943,199 )     (84,438,840 )
                 
      Net oil and gas properties     105,296,798       92,476,426  
                 
OTHER PROPERTY AND EQUIPMENT:                
    Land, buildings and improvements     2,795,000       -  
    Other property and equipment     3,492,904       2,066,760  
      6,287,904       2,066,760  
    Less: accumulated depreciation and amortization     (1,922,849 )     (1,822,925 )
                 
      Net other property and equipment     4,365,055       243,835  
                 
OTHER ASSETS AND DEFERRED CHARGES:                
  Commodity derivative instruments     548,573       818,637  
  Deposits     252,684       -  
  Receivables from affiliate     -       95,634  
  Goodwill     5,740,315       -  
  Other noncurrent assets     479,389       1,649,413  
                 
      Total other assets and deferred charges     7,020,961       2,563,684  
                 
      Total assets   $ 139,474,110     $ 111,631,968  
                 
                 
   
Yuma Energy, Inc.  
   
CONSOLIDATED BALANCE SHEETS - CONTINUED  
   
    September 30,
2014
(Unaudited)
   
December 31,
2013
 
LIABILITIES AND EQUITY                
                 
CURRENT LIABILITIES:                
Current maturities of debt   $ 565,166     $ 178,027  
Accounts payable, principally trade     23,648,139       15,116,560  
Commodity derivative instruments     -       677,132  
Asset retirement obligations     931,154       1,755,650  
Other accrued liabilities     2,390,907       1,127,283  
                 
Total current liabilities     27,535,366       18,854,652  
                 
LONG-TERM DEBT:                
Bank debt     24,965,000       31,215,000  
                 
OTHER NONCURRENT LIABILITIES:                
Preferred stock derivative liability, Series A and B     -       51,290,414  
Asset retirement obligations     11,591,497       8,942,029  
Commodity derivative instruments     20,849       218,649  
Deferred taxes     16,181,229       13,160,205  
Restricted stock units     178,922       102,532  
Other noncurrent liabilities     57,677       69,998  
                 
Total other noncurrent liabilities     28,030,174       73,783,827  
                 
                 
PREFERRED STOCK:                
Series A and B, subject to mandatory redemption     -       35,666,342  
                 
EQUITY:                
Common stock, no par value                
  (300 million shares authorized, 68,865,962 and 41,074,953 issued)     133,865,431       2,669,465  
Accumulated other comprehensive income     37,007       38,770  
Accumulated earnings (deficit)     (74,958,868 )     (50,596,088 )
                 
                 
Total equity     58,943,570       (47,887,853 )
                 
Total liabilities and equity   $ 139,474,110     $ 111,631,968  
                 
                 
   
Yuma Energy, Inc.  
   
CONSOLIDATED STATEMENTS OF OPERATIONS  
(Unaudited)  
   
    Three Months Ended September 30,     Nine Months Ended September 30,  
    2014     2013     2014     2013  
REVENUES:                                
Sales of natural gas and crude oil   $ 10,229,280     $ 5,878,954     $ 30,564,244     $ 19,431,906  
Other revenue     341,819       308,092       885,455       739,584  
  Total revenues     10,571,099       6,187,046       31,449,699       20,171,490  
                                 
EXPENSES:                                
Marketing cost of sales     408,559       298,492       1,012,577       936,632  
Lease operating     2,838,055       2,394,813       9,761,203       6,371,172  
Re-engineering and workovers     778,628       245,528       1,330,539       1,513,767  
General and administrative - stock-based compensation     521,978       17,961       598,818       427,374  
General and administrative - other     2,396,780       1,224,903       7,335,901       3,814,439  
Depreciation, depletion and amortization     3,865,675       3,203,017       15,604,283       7,315,103  
Asset retirement obligation accretion expense     150,628       187,025       438,717       464,306  
Other     55,102       136,222       83,117       127,602  
  Total expenses     11,015,405       7,707,961       36,165,155       20,970,395  
                                 
INCOME (LOSS) FROM OPERATIONS     (444,306 )     (1,520,915 )     (4,715,456 )     (798,905 )
                                 
OTHER INCOME (EXPENSE):                                
Change in fair value of preferred stock derivative liability - Series A and Series B     (11,172,928 )     15,382,964       (15,676,842 )     (7,581,234 )
Interest expense     (114,405 )     (64,076 )     (321,680 )     (488,788 )
Other, net     2,970       (23,325 )     5,634       (197,247 )
  Total other income (expense)     (11,284,363 )     15,295,563       (15,992,888 )     (8,267,269 )
                                 
NET INCOME (LOSS) BEFORE INCOME TAXES     (11,728,669 )     13,774,648       (20,708,344 )     (9,066,174 )
                                 
Income tax expense (benefit)     (576,632 )     (2,040,000 )     (1,710,632 )     (1,998,800 )
                                 
NET INCOME (LOSS)     (11,152,037 )     15,814,648       (18,997,712 )     (7,067,374 )
                                 
PREFERRED STOCK, SERIES A AND SERIES B:                                
Accretion     220,007       275,757       786,536       821,630  
Dividends paid in cash     346,192       -       445,152       59,850  
Dividends paid in kind     -       -       4,133,380       2,228,545  
                                 
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS   $ (11,718,236 )   $ 15,538,891     $ (24,362,780 )   $ (10,177,399 )
                                 
EARNINGS (LOSS) PER COMMON SHARE:                                
Basic   $ (0.25 )   $ 0.38     $ (0.56 )   $ (0.25 )
Diluted   $ (0.25 )   $ 0.24     $ (0.56 )   $ (0.25 )
                                 
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:                                
Basic     47,414,388       41,074,950       43,211,317       41,015,124  
Diluted     47,414,388       64,235,086       43,211,317       41,015,124  
                                 
                                 
   
Yuma Energy, Inc.  
CONSOLIDATED STATEMENTS OF CASH FLOWS  
(Unaudited)  
   
    Nine Months Ended September 30,  
    2014     2013  
                 
CASH FLOWS FROM OPERATING ACTIVITIES:                
Reconciliation of net loss to net cash provided by operating activities:                
Net loss   $ (18,997,712 )   $ (7,067,374 )
Increase in fair value of preferred stock derivative liability     15,676,842       7,581,234  
Depreciation, depletion and amortization of property and equipment     15,604,283       7,315,103  
Accretion of asset retirement obligation     438,717       464,306  
Stock-based compensation net of capitalized cost     598,819       427,374  
Amortization of other assets and liabilities     140,954       117,951  
Deferred tax expense (benefit)     (1,710,632 )     (1,998,800 )
Bad debt expense     85,101       149,611  
Gain on disposal of property and equipment     -       (19,500 )
Write off deferred offering costs     1,257,160       -  
Write off credit financing costs     -       313,652  
Amortization of benefit from commodity derivatives (sold) and purchased, net     (70,313 )     (54,450 )
Net commodity derivatives mark-to-market gain     (921,026 )     (439,478 )
Other     2,057       (1,716 )
                 
Changes in current operating assets and liabilities:                
Accounts receivable     1,868,318       (634,350 )
Note receivable     -       216  
Other current assets     (274,235 )     426,186  
Accounts payable     8,024,528       7,472,589  
Other current liabilities     1,007,872       951,624  
                 
Noncurrent payable to commodity derivative advisor and deferred commodity                
derivative premiums     (36,824 )     -  
                 
NET CASH PROVIDED BY OPERATING ACTIVITIES     22,693,909       15,004,178  
                 
                 
   
Yuma Energy, Inc.  
   
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED  
(Unaudited)  
   
    Nine Months Ended September 30,  
    2014     2013  
                 
CASH FLOWS FROM INVESTING ACTIVITIES:                
Capital expenditures on property and equipment   $ (17,901,264 )   $ (22,313,654 )
Proceeds from sale of property     307,600       698,766  
Cash received from merger     4,550,082       -  
Short-term investments retired     2,142,128       -  
Decrease (increase) in noncurrent receivable from affiliate     95,634       (2,493 )
                 
NET CASH USED BY INVESTING ACTIVITIES     (10,805,820 )     (21,617,381 )
                 
CASH FLOWS FROM FINANCING ACTIVITIES:                
Proceeds from borrowing     901,257       872,754  
Payments on borrowings     (514,118 )     (613,691 )
Change in borrowing on line of credit     (6,250,000 )     6,740,000  
Line of credit financing costs     (47,291 )     (556,276 )
Preparation costs to issue preferred stock     (165,034 )     -  
Deferred offering costs     -       (234,679 )
Cash dividends to preferred stockholders (Series A and Series B)     (445,152 )     (59,850 )
                 
NET CASH PROVIDED (USED) BY FINANCING ACTIVITIES     (6,520,338 )     6,148,258  
                 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS     5,367,751       (464,945 )
                 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD     4,194,511       5,285,022  
                 
CASH AND CASH EQUIVALENTS AT END OF PERIOD   $ 9,562,262     $ 4,820,077  
                 
Supplemental disclosure of cash flow information:                
Interest payments (net of interest capitalized)   $ 210,323     $ (23,569 )
Interest capitalized   $ 767,908     $ 788,214  
Supplemental disclosure of significant non-cash activity:                
Preferred dividends paid in kind (Series A and Series B)   $ 4,133,380     $ 2,228,545  
                 
                 

About Yuma Energy, Inc.

Yuma Energy, Inc. is a U.S.-based oil and gas company focused on the exploration for, and development of, conventional and unconventional oil and gas properties, primarily through the use of 3-D seismic surveys, in the U.S. Gulf Coast and California. The Company has employed a 3-D seismic-based strategy to build a multi-year inventory of development and exploration prospects. The Company's current operations are focused on onshore central Louisiana, where the Company is targeting the Austin Chalk, Tuscaloosa, Wilcox, Frio, Marg Tex and Hackberry formations. In addition, the Company has a non-operated position in the Bakken Shale in North Dakota and operated positions in Kern and Santa Barbara Counties in California. As a result of the transaction described below in "Recent Developments," the Company underwent a substantial change in ownership, management, assets and business strategy, all effective as of September 10, 2014. Our common stock is traded on the NYSE MKT under the trading symbol "YUMA." For more information about Yuma Energy, Inc., please visit our website at www.yumaenergyinc.com.

Recent Developments

On September 10, 2014, a wholly-owned subsidiary of the Company merged with and into Yuma Energy, Inc., a Delaware corporation ("Yuma Co."), in exchange for 66,336,701 shares of common stock and the Company changed its name to "Yuma Energy, Inc." (the "merger"). As a result of the 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 merger was accounted for as a reverse acquisition of the Company by Yuma Co.

Subsequent to the merger, Sam L. Banks assumed the role of Chairman, President and Chief Executive Officer, Kirk F. Sprunger became Chief Financial Officer, Treasurer and Corporate Secretary, and Paul D. McKinney became Executive Vice President and Chief Operating Officer. Our board of directors was reconstituted to include the directors of Yuma Co., Sam L. Banks, James W. Christmas, Frank A. Lodzinski, Ben T. Morris, Richard K. Stoneburner, and Richard W. Volk. Also, as part of the merger, our headquarters were relocated to Houston, Texas.

Forward-Looking Statements

This release contains 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"). Statements that are not strictly historical statements constitute forward-looking statements and may often, but not always, be identified by the use of such words such as "expects," "believes," "intends," "anticipates," "plans," "estimates," "potential," "possible," or "probable" or statements that certain actions, events or results "may," "will," "should," or "could" be taken occur or be achieved. The forward-looking statements include statements about future operations, estimates of reserve and production volumes. Forward-looking statements are based on current expectations and assumptions and analyses made by the Company in light of experience and perception of historical trends, current conditions and expected future developments, as well as other factors appropriate under the circumstances. However, whether actual results and developments will conform with expectations is subject to a number of risks and uncertainties, including but not limited to: fluctuations in oil and gas prices; the risks of the oil and gas industry (for example, operational risks in drilling and exploring for, developing and producing crude oil and natural gas; risks and uncertainties involving geology of oil and gas deposits); the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to future production, costs and expenses; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; health, safety and environmental risks and risks related to weather; inability of management to execute its plans to meet its goals, shortages of drilling equipment, oil field personnel and services, unavailability of gathering systems, pipelines and processing facilities and the possibility that government policies may change. The Company's annual report on Form 10-K for the year ended December 31, 2013, quarterly reports on Form 10-Q, recent current reports on Form 8-K, and other Securities and Exchange Commission filings discuss some of the important risk factors identified that may affect its business, results of operations, and financial condition. The Company undertakes no obligation to revise or update publicly any forward-looking statements for any reason.

For more information, please contact:

James J. Jacobs
Vice President - Corporate and Business Development
Yuma Energy, Inc.
1177 West Loop South, Suite 1825
Houston, TX 77027
Telephone: (713) 968-7000