Attached files
| file | filename |
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| 8-K - CURRENT REPORT - Yuma Energy, Inc. | yuma_8k.htm |
Exhibit 99.1
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Yuma Energy, Inc. |
NEWS RELEASE
Yuma Energy, Inc. Announces 2014 Financial Results
and Provides an Operational Overview
HOUSTON, TX – (Marketwired – March 30, 2015) – Yuma Energy, Inc. (NYSE MKT: YUMA) (the “Company” or “Yuma”) today announced its financial results for the year ended December 31, 2014 and provided an operational overview relating to its properties.
Year Ended December 31, 2014 Highlights
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-
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Production averaged 2,143 Boe/d compared to 1,369 Boe/d for 2013, representing a 57% increase.
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-
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Crude oil revenues were approximately $21.8 million, an increase of 13% compared to 2013.
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-
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Natural gas revenues were approximately $12.5 million, an increase of 107% compared to 2013.
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Operational Overview
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, 2014, we held approximately 69,470 net acres in the field. The acreage is located within an existing field which has previously been partially developed. Based on our technical analysis and independent third-party engineering, we believe there are approximately 67 operated proved undeveloped locations and 14 non-operated proved undeveloped locations that are either held by production or leases.
In the fourth quarter of 2014, we 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. Upon completion of the Crosby 14-1, we shut the well in to install surface facilities and to drill a salt water disposal well. In December 2014, we produced the well for three days to test and complete the installation of the facilities. In January of 2015 we began to produce and clean-up the production from the Crosby 14-1 well. Although early production results were encouraging, with higher oil cuts than expected, drilling mud and cuttings accumulated in the well which prevented it from flowing. We are planning operations designed to reduce or eliminate these restrictions. Work-over operations are being prepared to bring the well back on production. We hold a 61% working interest in this well.
La Posada – Bayou Hebert Field, Vermilion Parish, Louisiana. We have a 12.5% working interest in La Posada – Bayou Hebert Field. The primary objectives were the Lower Planulina Cris R sands, at a depth from approximately 17,700 to 18,250 feet. We initially generated the exploration prospect by utilizing data from a 3-D seismic survey, which resulted in a significant discovery.
The prospect was successfully tested in 2011 on the southern portion of the structure by PetroQuest Energy, Inc., the operator. A brief summary of the drilling activity to date is as follows:
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1.
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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.
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2.
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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.
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3.
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The Broussard No. 1 well (partially drilled and temporarily abandoned in 2007) was re-entered and sidetracked to the upper Cris R-2 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.
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In November 2014, after encountering excess water production relating to the wells, the operator reconfigured the production facilities and gross production averaged approximately 52.6 MMcf/d of natural gas and 970 Bbl/d of oil (4.7 MMcf/d and 87 Bbl/d net) during the fourth quarter of 2014. During the last week in January 2015, the operator completed the installation of higher capacity water handling equipment to handle increased water production from the Broussard No. 2 and the Thibodeaux No. 1. With the installation of this equipment, the operator plans to optimize gas production within the water handling limits of the upgraded facilities. As of March 15, 2015, the field was producing approximately 59 MMcf/d of natural gas and 1,100 Bbl/d of oil gross (5.3 MMcf/d and 98 Bbl/d net). Future potential production increases and the timing of potentially recompleting the Thibodeaux No. 1 from its current “C” zone to the overlying “B” zone will depend on the performance and optimization of the wells.
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 we 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 was drilled to a shallow Miocene target (natural gas). The shallow Miocene well has produced out and has been shut in.
We have since drilled two development wells offsetting our Lower Tuscaloosa discoveries in addition to two development wells offsetting our Wilcox discovery. One of our Wilcox development wells, the Blackwell 39-1 was drilled and completed on January 14, 2015 and has averaged 73 Bbl/d of oil gross when producing during the two months ended March 16, 2015. We anticipate placing the Blackwell 39-1 on pump during the second quarter of 2015.
Currently, four wells are producing from the lower Tuscaloosa sands and three wells are producing from the Wilcox. The average daily production from the seven wells during the three months ended December 31, 2014 was approximately 391 Bbl/d of oil gross (90 Bbl/d net).
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 December 31, 2014, we temporarily shut in a portion of the field to repair a salt water disposal well which curtailed production and consequently resulted in lower revenues from the field. Normal production levels in the field are approximately 250 Bbl/d of oil gross (162 Bbl/d net).
Gardner Island and Branville Bay, St. Bernard Parish, Louisiana. During the fourth quarter of 2014, we performed repair work on the salt water disposal well servicing the two fields which was completed in January 2015. This resulted in reduced production and revenues from the field in the fourth quarter due to the downtime for the repair. Since the repair, the fields were produced for approximately six weeks and then shut in for facility upgrades. We anticipate completing the upgrades in March and restoring production to approximately 250 Bbl/d gross (63 Bb/d net). Additionally, during the fourth quarter of 2014 we acquired additional interest in our Gardner Island field bringing our working interest from 7% to 34%
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 have recently finished drilling our Anaconda prospect, the Talbot 23-1, where we hold approximately a 45% working interest after casing point. This single well prospect is unique in that it encountered both Hackberry and Marg Tex objectives.
In the Marg Tex interval, the well logged approximately 45 feet of hydrocarbon bearing pay in four Marg Tex sands. In the Hackberry interval, we logged approximately 45 feet of hydrocarbon bearing pay in two Hackberry sands. We plan to begin completion and testing operations in the second quarter of 2015.
Cat Canyon Field, Santa Barbara County, California. Our Cat Canyon field is a legacy asset that was developed and owned by Pyramid Oil Company prior to our merger completed on September 10, 2014. The field produces from the Monterey formation 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 fracking) and are put on pump immediately. We plan to drill our first operated well on this property in 2015.
Bakken – Yellowstone and Southeast Homerun. At December 31, 2014, we held an average 5% non-operated working interest in 18,513 gross acres (674 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 gross drilling locations remain across our Bakken asset. In addition, we believe significant future infill and Three Forks development upside potential exists on our acreage.
Oil and Natural Gas Reserves
Estimated Proved Reserves
The table below summarizes our estimated proved reserves at December 31, 2014 based on the report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm. In preparing its report, NSAI evaluated 100% of our properties at December 31, 2014. The information in the following table does not give any effect to or reflect our commodity derivatives.
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Oil
(MBbls)
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Natural Gas Liquids
(MBbls)
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Natural Gas
(MMcf)
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Total
(MBoe)(1)
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Present Value Discounted at 10%
($ in thousands) (2)
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Proved developed (3)
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Total proved developed
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2,035 | 312 | 7,787 | 3,645 | $ | 94,631 | ||||||||||||||
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Proved undeveloped (3)
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Total proved undeveloped
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9,497 | 2,167 | 27,473 | 16,243 | 286,415 | |||||||||||||||
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Total proved (3)
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11,532 | 2,479 | 35,260 | 19,888 | $ | 381,046 | ||||||||||||||
(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).
(2) Present Value Discounted at 10% (“PV10”) is a Non-GAAP measure that differs from the GAAP measure “standardized measure of discounted future net cash flows” in that PV10 is calculated without regard to future income taxes. Management believes that the presentation of the PV10 value is relevant and useful to investors because it presents the estimated discounted future net cash flows attributable to our estimated proved reserves independent of our income tax attributes, thereby isolating the intrinsic value of the estimated future cash flows attributable to our reserves. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, we believe the use of a pre-tax measure provides greater comparability of assets when evaluating companies. For these reasons, management uses, and believes the industry generally uses, the PV10 measure in evaluating and comparing acquisition candidates and assessing the potential return on investment related to investments in oil and natural gas properties. PV10 does not necessarily represent the fair market value of oil and natural gas properties.
PV10 is not a measure of financial or operational performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. For a presentation of the standardized measure of discounted future net cash flows, see Note X – Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities in the Notes to the Consolidated Financial Statements contained in our annual report on Form 10-K for the year ended December 31, 2014. The table below titled “Non-GAAP Reconciliation” provides a reconciliation of PV10 to the standardized measure of discounted future net cash flows.
Non-GAAP Reconciliation ($ in thousands)
The following table reconciles our direct interest in oil, natural gas and natural gas liquids reserves as of December 31, 2014:
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Present value of estimated future net revenues (PV10)
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$ | 381,046 | ||
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Future income taxes discounted at 10%
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(86,591 | ) | ||
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Standardized measure of discounted future net cash flows
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$ | 294,455 |
(3) Proved reserves were calculated using prices equal to the twelve-month unweighted arithmetic average of the first-day-of-the-month prices for each of the preceding twelve months, which were $91.48 per Bbl (WTI) and $4.35 per MMBtu (HH), for the year ended December 31, 2014. Adjustments were made for location and grade.
Financial Results
Sales and Other Operating Revenues
The following table presents the net quantities of oil, natural gas and natural gas liquids produced and sold by us for the years ended December 31, 2014, 2013 and 2012, and the average sales price per unit sold.
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Years Ended December 31,
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2014
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2013
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2012
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Production volumes:
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Crude oil and condensate (Bbl)
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231,816 | 184,349 | 154,437 | |||||||||
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Natural gas (Mcf)
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2,714,586 | 1,580,468 | 515,112 | |||||||||
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Natural gas liquids (Bbl)
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97,783 | 51,875 | 9,571 | |||||||||
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Total (Boe) (1)
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782,030 | 499,635 | 249,860 | |||||||||
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Average prices realized:
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Excluding commodity derivatives (both realized and unrealized):
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Crude oil and condensate (per Bbl)
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$ | 93.98 | $ | 104.26 | $ | 107.57 | ||||||
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Natural gas (per Mcf)
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$ | 4.62 | $ | 3.83 | $ | 3.07 | ||||||
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Natural gas liquids (per Bbl)
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$ | 38.44 | $ | 40.17 | $ | 42.67 | ||||||
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Including commodity derivatives (realized only):
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Crude oil and condensate (per Bbl)
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$ | 91.74 | $ | 102.46 | $ | 106.45 | ||||||
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Natural gas (per Mcf)
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$ | 4.32 | $ | 4.08 | $ | 4.07 | ||||||
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Natural gas liquids (per Bbl)
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$ | 38.44 | $ | 40.17 | $ | 42.67 | ||||||
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(1)
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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).
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The following table presents our revenues for the years ended December 31, 2014, 2013 and 2012.
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Years Ended December 31,
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2014
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2013
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2012
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Revenues:
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Crude oil and condensate sales
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$ | 21,785,636 | $ | 19,220,185 | $ | 16,613,315 | ||||||
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Natural gas sales
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12,542,671 | 6,049,500 | 1,581,783 | |||||||||
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Natural gas liquids sales
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3,758,875 | 2,083,905 | 408,389 | |||||||||
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Realized gain/(loss) on commodity derivatives
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(1,326,467 | ) | 72,076 | 341,066 | ||||||||
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Unrealized gain/(loss) on commodity derivatives
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4,724,985 | (231,886 | ) ) | 1,256,918 | ||||||||
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Gas marketing sales
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572,210 | 881,823 | 1,080,644 | |||||||||
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Other revenue
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1,278,217 | 1,066,969 | 601,794 | |||||||||
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Total revenues
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$ | 43,336,127 | $ | 29,142,572 | $ | 21,883,909 | ||||||
NON-GAAP FINANCIAL MEASURES
Adjusted EBITDA
The following table reconciles reporting net income to EBITDA and Adjusted EBITDA for the periods indicated:
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Years Ended December 31,
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2014
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2013
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2012
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Net Income (Loss)
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$ | (20,225,150 | ) | $ | (33,050,103 | ) | $ | (14,769,468 | ) | |||
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Add: Depreciation, depletion & amortization of property and equipment
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19,664,991 | 12,077,368 | 5,074,070 | |||||||||
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Add: Interest expense, net of interest income and amounts capitalized
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302,568 | 560,340 | 201,945 | |||||||||
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Add (deduct): Income tax expense (benefit)
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(2,553,854 | ) | 3,080,272 | 3,098,309 | ||||||||
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EBITDA
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(2,811,445 | ) | (17,332,123 | ) | (6,395,144 | ) | ||||||
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Add: Costs to obtain a public listing
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2,935,536 | 24,592 | - | |||||||||
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Add: Increase in value of preferred stock derivative liability
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15,676,842 | 26,258,559 | 17,098,504 | |||||||||
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Add: Stock based compensation net of capitalized cost
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3,388,321 | 452,058 | - | |||||||||
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Add: Accretion of asset retirement obligation
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604,511 | 668,497 | 265,323 | |||||||||
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Add: Bank mandated commodity derivative novation cost
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- | 175,000 | - | |||||||||
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Deduct: Amortization of benefit from commodity derivatives sold
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(93,750 | ) | (72,600 | ) | (112,508 | ) | ||||||
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Add (deduct): Net commodity derivatives mark-to-market loss (gain)
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(4,724,985 | ) | 231,886 | (1,256,918 | ) | |||||||
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Adjusted EBITDA
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$ | 14,975,030 | $ | 10,405,869 | $ | 9,599,257 | ||||||
“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, stock based compensation net of capitalized cost, 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 December 31, 2014, we had a $40.0 million conforming borrowing base. At December 31, 2014, we had an undrawn amount of $17.1 million under our credit facility.
In addition, we had a cash and cash equivalents balance of $11.6 million and short-term investments of $1.2 million at December 31, 2014. This resulted in Liquidity (1) of approximately $29.9 million as of December 31, 2014.
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(1) Liquidity can vary from period to period for Yuma 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.
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Management Comments
Sam L. Banks, Chairman, President and Chief Executive Officer of Yuma Energy, Inc. commented, “2014 was a transforming year for Yuma. We closed our merger with Pyramid Oil Company on September 10, 2014 and began trading on the NYSE MKT under the symbol “YUMA”. We made important strides with the integration of Pyramid and made several nice wells on our Livingston project. We grew production and EBITDA from the previous year and executed on our acquisition strategy by making several small but accretive acquisitions. We also successfully accessed the capital markets by raising approximately $11.2 million in gross proceeds through the issuance of our 9.25% Series A Cumulative Redeemable Preferred Stock. We continue to have a significant inventory of oil and gas assets and look forward to growing production during 2015. We have made great additions to our operational team, including the addition of Paul McKinney as our new Chief Operating Officer, and we are well positioned to execute on our business strategy of transitioning existing proved undeveloped reserves and our 3-D prospect inventory into production, as well as growing the Company through cash flow positive acquisitions. Lastly, we continue to have a seasoned team with more than 30 years of successful exploration and production activities and look forward to organically growing the Company with an emphasis on generating viable prospects that will work in the current commodity price environment.”
Yuma Energy, Inc.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
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December 31,
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| 2014 | 2013 | |||||||
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ASSETS
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CURRENT ASSETS:
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Cash and cash equivalents
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$ | 11,558,322 | $ | 4,194,511 | ||||
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Short-term investments
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1,170,868 | - | ||||||
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Accounts receivable, net of allowance for doubtful accounts:
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Trade
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9,739,737 | 10,837,211 | ||||||
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Officers and employees
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316,077 | 155,080 | ||||||
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Other
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697,991 | 417,850 | ||||||
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Commodity derivative instruments
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3,338,537 | - | ||||||
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Prepayments
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782,234 | 433,991 | ||||||
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Deferred taxes
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245,922 | 146,964 | ||||||
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Other deferred charges
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342,798 | 162,416 | ||||||
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Total current assets
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28,192,486 | 16,348,023 | ||||||
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OIL AND GAS PROPERTIES (full cost method):
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Not subject to amortization
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25,707,052 | 24,051,278 | ||||||
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Subject to amortization
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186,530,863 | 152,863,988 | ||||||
| 212,237,915 | 176,915,266 | |||||||
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Less: accumulated depreciation, depletion and amortization
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(103,929,493 | ) | (84,438,840 | ) | ||||
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Net oil and gas properties
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108,308,422 | 92,476,426 | ||||||
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OTHER PROPERTY AND EQUIPMENT:
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Land, buildings and improvements
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2,795,000 | - | ||||||
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Other property and equipment
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3,439,688 | 2,066,760 | ||||||
| 6,234,688 | 2,066,760 | |||||||
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Less: accumulated depreciation and amortization
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(1,909,352 | ) | (1,822,925 | ) | ||||
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Net other property and equipment
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4,325,336 | 243,835 | ||||||
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OTHER ASSETS AND DEFERRED CHARGES:
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Commodity derivative instruments
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1,403,109 | 818,637 | ||||||
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Deposits
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264,064 | 7,300 | ||||||
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Receivables from affiliate
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- | 95,634 | ||||||
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Goodwill
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5,349,988 | - | ||||||
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Other noncurrent assets
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262,200 | 1,642,113 | ||||||
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Total other assets and deferred charges
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7,279,361 | 2,563,684 | ||||||
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Total assets
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$ | 148,105,605 | $ | 111,631,968 | ||||
Yuma Energy, Inc.
CONSOLIDATED BALANCE SHEETS – CONTINUED
(Unaudited)
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December 31,
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2014
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2013
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LIABILITIES AND EQUITY
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CURRENT LIABILITIES:
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Current maturities of debt
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$ | 282,843 | $ | 178,027 | ||||
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Accounts payable, principally trade
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25,004,364 | 15,116,560 | ||||||
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Commodity derivative instruments
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- | 677,132 | ||||||
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Asset retirement obligations
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- | 1,755,650 | ||||||
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Deferred taxes
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471,995 | - | ||||||
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Other accrued liabilities
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1,419,565 | 1,127,283 | ||||||
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Total current liabilities
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27,178,767 | 18,854,652 | ||||||
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LONG-TERM DEBT:
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Bank debt
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22,900,000 | 31,215,000 | ||||||
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OTHER NONCURRENT LIABILITIES:
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Preferred stock derivative liability, Series A and B
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- | 51,290,414 | ||||||
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Asset retirement obligations
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12,487,770 | 8,942,029 | ||||||
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Commodity derivative instruments
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- | 218,649 | ||||||
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Deferred taxes
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14,388,662 | 13,160,205 | ||||||
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Restricted stock units
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71,569 | 102,532 | ||||||
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Other
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22,451 | 69,998 | ||||||
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Total other noncurrent liabilities
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26,970,452 | 73,783,827 | ||||||
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PREFERRED STOCK:
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Series A and B, subject to mandatory redemption
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- | 35,666,342 | ||||||
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EQUITY:
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Common stock, no par value
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||||||||
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(300 million shares authorized, 69,139,869 and 41,074,950 issued)
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137,469,772 | 2,669,465 | ||||||
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Preferred stock
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9,958,217 | - | ||||||
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Accumulated other comprehensive income
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38,801 | 38,770 | ||||||
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Accumulated earnings (deficit)
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(76,410,404 | ) | (50,596,088 | ) | ||||
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Total equity
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71,056,386 | (47,887,853 | ) | |||||
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Total liabilities and equity
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$ | 148,105,605 | $ | 111,631,968 | ||||
Yuma Energy, Inc.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
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Years Ended December 31,
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2014
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2013
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2012
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REVENUES:
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Sales of natural gas and crude oil
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$ | 42,057,910 | $ | 28,075,603 | $ | 21,282,115 | ||||||
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Other revenue
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1,278,217 | 1,066,969 | 601,794 | |||||||||
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Total revenues
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43,336,127 | 29,142,572 | 21,883,909 | |||||||||
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EXPENSES:
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Marketing cost of sales
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1,045,177 | 1,234,308 | 891,118 | |||||||||
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Lease operating
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12,816,725 | 9,316,364 | 5,098,868 | |||||||||
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Re-engineering and workovers
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3,084,972 | 2,521,707 | 433,599 | |||||||||
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General and administrative – stock-based compensation
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3,388,321 | 452,058 | - | |||||||||
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General and administrative – other
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9,434,294 | 5,603,475 | 4,339,362 | |||||||||
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Depreciation, depletion and amortization
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19,664,991 | 12,077,368 | 5,074,070 | |||||||||
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Asset retirement obligation accretion expense
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604,511 | 668,497 | 265,323 | |||||||||
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Other
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98,476 | 171,774 | 151,240 | |||||||||
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Total expenses
|
50,137,467 | 32,045,551 | 16,253,580 | |||||||||
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INCOME (LOSS) FROM OPERATIONS
|
(6,801,340 | ) | (2,902,979 | ) | 5,630,329 | |||||||
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OTHER INCOME (EXPENSE):
|
||||||||||||
|
Change in fair value of preferred stock derivative liability -
|
||||||||||||
|
Series A and Series B
|
(15,676,842 | ) | (26,258,559 | ) | (17,098,504 | ) | ||||||
|
Interest expense
|
(326,200 | ) | (567,676 | ) | (210,083 | ) | ||||||
|
Other, net
|
25,378 | (240,617 | ) | 7,099 | ||||||||
|
Total other income (expense)
|
(15,977,664 | ) | (27,066,852 | ) | (17,301,488 | ) | ||||||
|
NET LOSS BEFORE INCOME TAXES
|
(22,779,004 | ) | (29,969,831 | ) | (11,671,159 | ) | ||||||
|
Income tax expense (benefit)
|
(2,553,854 | ) | 3,080,272 | 3,098,309 | ||||||||
|
NET LOSS
|
(20,225,150 | ) | (33,050,103 | ) | (14,769,468 | ) | ||||||
|
PREFERRED STOCK:
|
||||||||||||
|
Dividends paid in cash, Series A perpetual preferred
|
224,098 | - | - | |||||||||
|
Accretion (Series A and Series B)
|
786,536 | 1,101,972 | 963,900 | |||||||||
|
Dividends paid in cash (Series A and Series B)
|
445,152 | 145,900 | 1,362,437 | |||||||||
|
Dividends paid in kind (Series A and Series B)
|
4,133,380 | 5,412,281 | - | |||||||||
|
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS
|
$ | (25,814,316 | ) | $ | (39,710,256 | ) | $ | (17,095,805 | ) | |||
|
LOSS PER COMMON SHARE:
|
||||||||||||
|
Basic
|
$ | (0.52 | ) | $ | (0.97 | ) | $ | (0.42 | ) | |||
|
Diluted
|
$ | (0.52 | ) | $ | (0.97 | ) | $ | (0.42 | ) | |||
|
WEIGHTED AVERAGE NUMBER OF COMMON
|
||||||||||||
|
SHARES OUTSTANDING:
|
||||||||||||
|
Basic
|
49,678,444 | 41,074,953 | 40,896,222 | |||||||||
|
Diluted
|
49,678,444 | 41,074,953 | 40,896,222 | |||||||||
Yuma Energy, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
|
Years Ended December 31,
|
||||||||||||
|
2014
|
2013
|
2012
|
||||||||||
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
||||||||||||
|
Reconciliation of net loss to net cash provided by operating activities
|
||||||||||||
|
Net loss
|
$ | (20,225,150 | ) | $ | (33,050,103 | ) | $ | (14,769,468 | ) | |||
|
Increase in fair value of preferred stock derivative liability
|
15,676,842 | 26,258,559 | 17,098,504 | |||||||||
|
Depreciation, depletion and amortization of property and equipment
|
19,664,991 | 12,077,368 | 5,074,070 | |||||||||
|
Accretion of asset retirement obligation
|
604,511 | 668,497 | 265,323 | |||||||||
|
Stock-based compensation net of capitalized cost
|
3,388,321 | 452,058 | - | |||||||||
|
Amortization of other assets and liabilities
|
188,669 | 166,608 | 86,421 | |||||||||
|
Deferred tax expense (benefit)
|
(2,553,854 | ) | 3,080,272 | 3,098,309 | ||||||||
|
Bad debt expense
|
97,068 | 193,601 | 210,187 | |||||||||
|
Write off deferred offering costs
|
1,257,160 | - | - | |||||||||
|
Write off credit financing costs
|
- | 313,652 | 30,000 | |||||||||
|
Amortization of benefit from commodity derivatives (sold) and
|
||||||||||||
|
purchased, net
|
(93,750 | ) | (72,600 | ) | (112,508 | ) | ||||||
|
Net commodity derivatives mark-to-market (gain) loss
|
(4,724,985 | ) | 231,886 | (1,256,918 | ) | |||||||
|
Other
|
5,448 | (21,328 | ) | (55,463 | ) | |||||||
|
Changes in current operating assets and liabilities:
|
||||||||||||
|
Accounts receivable
|
976,093 | (5,589,741 | ) | 403,516 | ||||||||
|
Other current assets
|
(267,386 | ) | 869,550 | (689,537 | ) | |||||||
|
Restricted cash
|
- | - | 341,474 | |||||||||
|
Accounts payable
|
10,690,790 | 9,115,792 | (6,420,733 | ) | ||||||||
|
Other current liabilities
|
(170,921 | ) | 148,834 | (56,514 | ) | |||||||
|
Other
|
(47,547 | ) | 69,998 | - | ||||||||
|
NET CASH PROVIDED BY OPERATING ACTIVITIES
|
24,466,300 | 14,912,903 | 3,246,663 | |||||||||
Yuma Energy, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS – CONTINUED
(Unaudited)
|
Years Ended December 31,
|
||||||||||||
|
2014
|
2013
|
2012
|
||||||||||
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||
|
Capital expenditures on property and equipment
|
$ | (25,526,887 | ) | $ | (28,152,714 | ) | $ | (30,146,557 | ) | |||
|
Proceeds from sale of property
|
667,267 | 902,166 | 1,386,649 | |||||||||
|
Cash received from merger
|
4,550,082 | - | - | |||||||||
|
Short-term investments retired
|
2,125,541 | - | - | |||||||||
|
Decrease (increase) in noncurrent receivable from affiliate
|
95,634 | (2,493 | ) | (2,486 | ) | |||||||
|
NET CASH USED IN INVESTING ACTIVITIES
|
(18,088,363 | )( | (27,253,041 | ) | (28,762,394 | ) | ||||||
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||
|
Proceeds from borrowing
|
901,257 | 872,754 | 606,238 | |||||||||
|
Payments on borrowings
|
(796,441 | ) | (878,328 | ) | (659,101 | ) | ||||||
|
Change in borrowing on line of credit
|
(8,315,000 | ) | 13,340,000 | 14,900,000 | ||||||||
|
Line of credit financing costs
|
(92,909 | ) | (681,739 | ) | (280,166 | ) | ||||||
|
Net proceeds from issuance of preferred stock
|
9,958,217 | - | - | |||||||||
|
Deferred offering costs
|
- | (1,257,160 | ) | 17,183,705 | ||||||||
|
Cash dividends to preferred stockholders
|
(669,250 | ) | (145,900 | ) | (1,362,437 | ) | ||||||
|
Buy-out Yuma Production 1985, Ltd. minority interest partners
|
- | - | (245,422 | ) | ||||||||
|
Derivative instruments purchased
|
- | - | (16,004 | ) | ||||||||
|
Decrease in noncurrent payable to affiliate
|
- | - | (247,092 | ) | ||||||||
|
NET CASH PROVIDED BY FINANCING ACTIVITIES
|
985,874 | 11,249,627 | 29,879,721 | |||||||||
|
NET INCREASE (DECREASE) IN CASH AND
|
||||||||||||
|
CASH EQUIVALENTS
|
7,363,811 | (1,090,511 | ) | 4,363,990 | ||||||||
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
|
4,194,511 | 5,285,022 | 921,032 | |||||||||
|
CASH AND CASH EQUIVALENTS AT END OF PERIOD
|
$ | 11,558,322 | $ | 4,194,511 | $ | 5,285,022 | ||||||
|
Supplemental disclosure of cash flow information:
|
||||||||||||
|
Interest payments (net of interest capitalized)
|
$ | 175,009 | $ | 22,210 | $ | 160,720 | ||||||
|
Interest capitalized
|
$ | 1,059,350 | $ | 1,031,816 | $ | 681,090 | ||||||
|
Supplemental disclosure of significant non-cash activity:
|
||||||||||||
|
Preferred dividends paid in kind (Series A and Series B)
|
$ | 4,133,380 | $ | 5,412,281 | $ | - | ||||||
|
Change in capital expenditures financed by accounts payable
|
$ | 1,310,037 | $ | 1,904,581 | $ | (1,650,073 | ) | |||||
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 “Merger,” 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.
Merger
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, 2014, 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