YUMA ENERGY, INC. - 10-K - Management's Discussion and Analysis of Financial
Condition and Results of Operations.
The following discussion is intended to assist in understanding our results of
operations and our current financial condition. Our consolidated financial
statements and the accompanying notes included elsewhere in this report contain
additional information that should be referred to when reviewing this material.
The following discussion contains "forward-looking statements" that reflect our
future plans, estimates, beliefs and expected performance. We caution that
assumptions, expectations, projections, intentions or beliefs about future
events may, and often do, vary from actual results and the differences can be
material. Some of the key factors that could cause actual results to vary from
our expectations include changes in oil and natural gas prices, the timing of
planned capital expenditures, availability of acquisitions, joint ventures and
dispositions, uncertainties in estimating proved reserves and forecasting
production results, potential failure to achieve production from development
projects, operational factors affecting the commencement or maintenance of
producing wells, the condition of the capital and financial markets generally,
as well as our ability to access them, and uncertainties regarding environmental
regulations or litigation and other legal or regulatory developments affecting
our business, as well as those factors discussed below and elsewhere in this
report, all of which are difficult to predict. In light of these risks,
uncertainties and assumptions, the forward-looking events discussed may not
occur. See "Cautionary Statement Regarding Forward-Looking Statements" and Item
1A. "Risk Factors."
Overview
We are a
Houston
-based oil and gas company focused on the acquisition,
development, and exploration for conventional and unconventional oil and natural
gas resources in the U.S. Gulf Coast and
California
. 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 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
.
Recent developments
The prices of crude oil and natural gas have declined dramatically since
mid-year 2014, having recently reached multiyear lows, 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 looked to enter into a merger with Davis Petroleum Acquisition
Corp. to increase our liquidity and improve our financial position (see
description of the merger in Part II, Item 8. Notes to the Consolidated
Financial Statements, Note 24 - 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.
Reserves and non-cash full cost ceiling impairment
Our results of operations are heavily influenced by oil and natural gas prices,
which have significantly declined and have remained low during the last year.
These oil and natural gas price fluctuations are caused by changes in the global
and regional supply of and demand for oil and natural gas, market uncertainty,
economic conditions and a variety of additional factors. Since the inception of
our oil and natural gas activities, commodity prices have experienced
significant fluctuations, and additional changes in commodity prices may affect
the economic viability of and our ability to fund drilling projects, as well as
the economic valuation and economic recovery of oil and natural gas reserves.
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As discussed previously in this report, during 2015 commodity prices for crude
oil and natural gas experienced sharp declines, and this downward trend has
accelerated further into the first quarter of 2016, with crude oil prices
reaching a twelve-year low in February 2016. We have significantly reduced our
capital budget for 2016. In addition, we have purposely significantly reduced
the portion of our reserves that have historically been categorized as "proved
undeveloped" or "PUD," and have adjusted our drilling schedule and PUD bookings
due to the current economic price environment and our financial condition. We
have focused on our efforts to develop our acreage in the most efficient manner
possible and determine which potential locations will be most
profitable. Although we believe that we have a plan to develop our reserves, the
current environment and the industry's access to the capital markets may affect
our ability to execute this plan.
NSAI, our independent reserve engineers, estimated 100% of our proved reserves
as of December 31, 2015 and 2014. As of December 31, 2015, we had 13,261 MBoe of
estimated proved reserves as compared to 19,888 MBoe of estimated proved
reserves as of December 31, 2014. For prices used to value our reserves, See
Part II, Item 8. Notes to the Consolidated Financial Statements, Note 25 -
Supplementary Information on Oil and Natural Gas Exploration, Development and
Production Activities (Unaudited).
Potential future low commodity price impact on our development plans, reserves and full cost impairment
Oil and natural gas prices have remained low in the first quarter of 2016. If
prices remain at or below the current low levels, subject to numerous factors
and inherent limitations, and all other factors remain constant, we may incur a
non-cash full cost impairment during 2016, which will have an adverse effect on
our results of operations.
There are numerous uncertainties inherent in the estimation of proved reserves
and accounting for oil and natural gas properties in future periods. In addition
to unknown future commodity prices, other uncertainties include (i) changes in
drilling and completion costs, (ii) changes in oilfield service costs, (iii)
production results, (iv) our ability, in a low price environment, to
strategically drill the most economic locations in our targets, (v) income tax
impacts, (vi) potential recognition of additional proved undeveloped reserves,
(vii) any potential value added to our proved reserves when testing
recoverability from drilling unbooked locations and (viii) the inherent
significant volatility in the commodity prices for oil and natural gas recently
exemplified by the large changes in recent months.
Each of the above factors is evaluated on a quarterly basis and if there is a
material change in any factor it is incorporated into our internal reserve
estimation utilized in our quarterly accounting estimates. We use our internal
reserve estimates to evaluate, also on a quarterly basis, the reasonableness of
our reserve development plans for our reported reserves. Changes in
circumstance, including commodity pricing, economic factors and the other
uncertainties described above may lead to changes in our reserve development
plans.
We have set forth below a calculation of a potential future reduction of our
proved reserves. Such implied impairment and decrease in reserves should not be
interpreted to be indicative of our development plan or of our actual future
results. Each of the uncertainties noted above has been evaluated for material
known trends to be potentially included in the estimation of possible
first-quarter effects. Based on such review, we determined that the impact of
decreased commodity prices, changes to our reserves and future production due to
expiring leases, and the roll-off of our estimated production are the only
significant known variables in the following scenario.
Both our hypothetical first-quarter 2016 full cost ceiling calculation and our
hypothetical reserves estimates have been prepared by substituting (i) $46.26
per barrel for oil, and (ii) $2.40 per MMBtu for natural gas (the "Pro Forma
Prices") for the respective realized prices as of March 31, 2016. Changes to our
reserves and future production due to expiring leases were made as well as
changing the effective date of the evaluation from December 31, 2015 to March
31, 2016 to account for the roll-off of the estimated production and reduction
in reserves. All other inputs and assumptions have been held constant.
Accordingly, this estimation accounts for the impact of more current commodity
prices on the first-quarter 2016 realized prices that will be utilized in our
full cost ceiling calculation and our reserves estimate. The Pro Forma Prices
use a slightly modified realized price, calculated as the unweighted arithmetic
average of the first-day-of-the-month price for oil, natural gas liquids and
natural gas on the first day of the month for the 12 months ended March 1,
2016. Using this methodology, the estimated implied impact to our December 31,
2015 reserves of 13,261 MBoe would be a reduction of 3,478 MBoe. However, this
estimated reduction would not result in a first quarter ceiling test impairment
in 2016. We believe that substituting the Pro Forma Prices into our December 31,
2015 internal reserve estimates may help provide users with an understanding of
the potential first-quarter price impact on our March 31, 2016 full cost ceiling
test and in preparing our year-end reserve estimates.
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Mergers and acquisitions
On February 10, 2016, the Company and privately held Davis Petroleum Acquisition
Corp. ("Davis") entered into a definitive merger agreement for an all-stock
transaction. Upon completion of the transaction, we will reincorporate in
Delaware
, implement a one-for-ten reverse split of our common stock, and convert
each share of our existing Series A Preferred Stock into 35 shares of common
stock prior to giving effect for the reverse split (3.5 shares post reverse
split). Following these actions, we will issue additional shares of common stock
in an amount sufficient to result in approximately 61.1% of the common stock
being owned by the current common stockholders of Davis. In addition, we will
issue approximately 3.3 million shares of a new Series D preferred stock to
existing Davis preferred stockholders, which is estimated to have a conversion
price of approximately $5.70 per share, after giving effect for the reverse
split. The Series D preferred stock is estimated to have an aggregate
liquidation preference of approximately $18.7 million at closing, and will be
paid dividends in the form of additional shares of Series D preferred stock at a
rate of 7% per annum. Upon closing, there will be an aggregate of approximately
23.7 million shares of our common stock outstanding (after giving effect to the
reverse stock split and conversion of Series A Preferred Stock to common stock).
The transaction is expected to qualify as a tax-deferred reorganization under
Section 368(a) of the Code.
Results of Operations
Production
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, 2015, 2014
and 2013, and the average sales price per unit sold.
Years Ended December 31,
2015 2014
2013
Production volumes:
Crude oil and condensate (Bbl) 247,177 231,816 184,349
Natural gas (Mcf) 1,993,842 2,714,586 1,580,468
Natural gas liquids (Bbl) 74,511 97,783 51,875
Total (Boe) (1) 653,995 782,030 499,635
Average prices realized:
Excluding commodity derivatives:
Crude oil and condensate (per Bbl) $ 48.07 $ 93.98 $ 104.26
Natural gas (per Mcf) $ 2.60 $ 4.62 $
3.83
Natural gas liquids (per Bbl) $ 18.89 $ 38.44 $ 40.17
Including commodity derivatives:
Crude oil and condensate (per Bbl) $ 65.20 $ 101.98 $ 104.39
Natural gas (per Mcf) $ 3.00 $ 5.19 $
3.71
Natural gas liquids (per Bbl) $ 18.89 $ 38.44 $ 40.17
(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).
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Revenues
The following table presents our revenues for the years ended December 31, 2015,
2014 and 2013.
Years Ended December 31,
2015 2014 2013
Sales of natural gas and crude oil:
Crude oil and condensate $ 11,881,626 $ 21,785,636 $ 19,220,185
Natural gas 5,181,715 12,542,671 6,049,500
Natural gas liquids 1,407,512 3,758,875 2,083,905
Gain/(loss) on commodity derivatives 5,038,826 3,398,518
(159,810 )
Gas marketing 209,731 572,210 881,823
Total revenues $ 23,719,410 $ 42,057,910 $ 28,075,603
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"). For the years ended December 31, 2015, 2014
and 2013, LLS postings averaged $3.48, $3.02 and $9.58 over WTI,
respectively. 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 6.6% higher for the year ended December 31, 2015
than the crude oil volumes sold during the year ended December 31, 2014. This
increase was a result of increased production from
Livingston
and Main Pass 4
wells and a full year of production from our
California
assets, partially offset
by declines from Masters Creek and La Posada properties. In the
Livingston
area
fields, we focused on optimizing the artificial lift systems and reducing
downtime and workovers. At Main Pass 4, we re-engineered the facilities to
increase our water handling and disposal capacity and to improve run-times.
Realized crude oil prices experienced a 48.9% decrease from the year ended
December 31, 2014 to the year ended December 31, 2015.
Crude oil volumes sold increased by 25.7% for the year ended December 31, 2014
compared to the year ended December 31, 2013. New production came from two wells
and the newly acquired Pyramid wells, and was further enhanced by increased
sales on five wells after successful workover operations. Some reductions were
due to the shut-in of two wells for salt water disposal well work and declining
production from two other wells and the Bakken wells in
North Dakota
. Realized
crude oil prices experienced a 9.9% decrease from the year ended December 31,
2013 to the year ended December 31, 2014.
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. Natural gas liquids 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 year ended December 31, 2015 compared to the year ended December 31,
2014, we experienced a 26.6% decrease in natural gas volumes sold and a 23.8%
decrease in natural gas liquids sold primarily due to production declines in the
Bayou Hebert (La Posada) field, which were partially offset by new production
from our Talbot 23-1 well. During the same period, realized natural gas prices
decreased by 43.7% and realized natural gas liquids prices decreased by 50.9%.
For the year ended December 31, 2014 compared to the year ended December 31,
2013, a 71.8% increase in natural gas volumes sold was primarily due to
increased production from the
Crosby
12-1 and the net revenue increase at La
Posada, partially offset by production declines from the Broussard No. 2 and
Thibodeaux No. 1. These increases in natural gas sales led to increases in
natural gas liquids sales of 88.5%. During the same period, realized natural gas
prices increased by 20.6% and realized natural gas liquids prices decreased by
4.3%.
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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"), purchases and sells 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 Part II,
Item 8. Notes to the Consolidated Financial Statements, Note 24 - Subsequent
Events).
Expenses
Lease Operating Expenses
Our lease operating expenses ("LOE") and LOE per Boe for the years ended December 31, 2015, 2014 and 2013, are set forth below:
Years Ended December 31,
2015 2014 2013
Lease operating expenses $ 7,531,846 $ 7,350,237 $ 5,265,794
Severance, ad valorem taxes and marketing 3,869,463 5,466,488 4,050,570
Total LOE $ 11,401,309 $ 12,816,725 $ 9,316,364
LOE per Boe $ 17.43 $ 16.39 $ 18.65
LOE per Boe without severance, ad valorem taxes
and marketing $ 11.52 $ 9.40 $ 10.54
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 11.0% decrease in total LOE for the year ended December 31, 2015 compared to
the year ended December 31, 2014 was primarily due to operating cost reduction
initiatives implemented in our Greater Masters Creek Area,
Livingston
, and
California
. LOE per barrel of oil equivalent increased by 6.3% for the same
period generally due to the lower natural gas and natural gas liquids sales when
compared to the prior year.
The 37.6% increase in LOE for the year ended December 31, 2014 compared to the
year ended December 31, 2013 was primarily due to maintenance projects, an
increased working interest for the La Posada wells due to achieving payout, and
LOE for the
Crosby
12-1 well and the Pyramid properties acquired. LOE per barrel
of oil equivalent decreased by 12.1% for the same period generally due to
increased sales volumes.
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 years ended December 31, 2015, 2014 and 2013 totaled
$555,539, $3,084,972, and $2,521,707, respectively. Workover expenses decreased
by 82.0% in the year ended December 31, 2015 compared to the year ended December
31, 2014 primarily because of the high workover expenses incurred in 2014 to
restore salt water disposal at Gardner Island (Main Pass 4) and Raccoon Island
(Main Pass 2). Additionally, in 2015 the artificial lift optimization projects
completed in
Livingston
, the re-engineered facilities installed at Main Pass 4,
and the cost reduction initiatives at Masters Creek and in
California
led to
fewer workovers, down time, and less activity overall. Workover expenses
increased by 22.3% in the year ended December 31, 2014 compared to the same
period in 2013 due to work on the Gardner Island and Raccoon Island salt water
disposal wells. Additionally, LOE per Boe, including re-engineering and
workovers, for the years ended December 31, 2015, 2014 and 2013 totaled $18.28,
$20.33 and $23.69, respectively. All re-engineering work performed in 2015 was
completed prior to July 2015. Additional work planned for 2015 was deferred due
to commodity prices.
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General and Administrative Expenses
Our general and administrative ("G&A") expenses for the years ended December 31, 2015, 2014 and 2013, are summarized as follows:
Years Ended December 31,
2015 2014 2013
General and administrative:
Stock-based compensation $ 3,086,209 $ 4,293,855 $ 589,164
Capitalized (796,898 ) (905,534 ) (137,106 )
Net stock-based compensation 2,289,311 3,388,321 452,058
Other 9,727,419 10,692,639 7,186,069
Capitalized (2,293,115 ) (2,536,562 ) (2,649,563 )
Net other 7,434,304 8,156,077 4,536,506
Net general and administrative expenses $ 9,723,615 $ 11,544,398 $ 4,988,564
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 year ended December 31, 2015, net G&A expenses were $1,820,783 (15.8%)
less than the amount for the prior year ended December 31, 2014. The reduction
in G&A expenses was primarily attributed to a decrease in stock-based
compensation, along with higher costs in 2014 for professional fees associated
with the merger and costs to explore other public listing options. Stock-based
compensation net of amounts capitalized totaled $2,289,311 and $3,388,321 for
fiscal years 2015 and 2014, respectively. Non-recurring professional costs
related to the merger and costs to explore other public listing options totaled
$113,997 and $2,935,536 in fiscal years 2015 and 2014, respectively. Also
included in 2015 G&A costs were $406,556 in non-recurring severance benefits for
several employees terminated at year-end.
For the year ended December 31, 2014, net G&A expenses were $6,555,834 (131.4%)
over the amount for the prior year ended December 31, 2013. The increases were
due in large part to the initial amortization of restricted stock awards at the
time of the merger, triggered as a result of the condition of the Company going
public. This stock-based compensation, net of amounts capitalized, totaled
$3,388,321 and $452,058 for fiscal years 2014 and 2013,
respectively. Additionally, non-recurring professional costs associated with the
merger and costs to explore other public listing options totaled $2,935,536 and
$24,592 in fiscal years 2014 and 2013, respectively. Excluding these costs for
prior stock-based compensation and the merger, along with Pyramid's 2014 G&A
costs of $127,534, net G&A expenses for 2014 were $581,093, or 12.9%, over
2013. This increase was primarily the result of five (net) employee additions in
2014.
Depreciation, Depletion and Amortization
Our depreciation, depletion and amortization ("DD&A") for the years ended December 31, 2015, 2014 and 2013, is summarized as follows:
Years Ended December 31,
2015 2014 2013
DD&A $ 13,651,207 $ 19,664,991 $ 12,077,368
DD&A per Boe $ 20.87 $ 25.15 $ 24.17
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DD&A per Boe decreased by 17.0% for the year ended December 31, 2015 compared to
the year ended December 31, 2014. The decrease resulted primarily from the
reduction of the net quantities of natural gas and natural gas liquids sold by
us and the reduction of the proved reserves associated with the reclassification
of proved undeveloped reserves to non-proved. The net quantities of oil, natural
gas and natural gas liquids produced and sold by us increased by 56.5% for the
year ended December 31, 2014 compared to the year ended December 31, 2013. This
increase in production was the primary factor for the 4.1% increase in DD&A per
Boe in 2014 over 2013. See "Production" above for the volumes of oil, natural
gas and natural gas liquids production.
NON-GAAP FINANCIAL MEASURES
Adjusted EBITDA
The following table reconciles reported net income to Adjusted EBITDA for the
periods indicated:
Years Ended December 31,
2015 2014 2013
Net Income (loss) $ (11,005,038 ) $
(20,225,150 ) $ (33,050,103 ) Depreciation, depletion & amortization of property and equipment
13,651,207 19,664,991 12,077,368
Interest expense, net of interest income and
amounts capitalized 436,836 302,568 560,340
Income tax benefit (7,983,039 ) (2,553,854 ) 3,080,272
Goodwill impairment 5,349,988 - -
Stock-based compensation net of capitalized cost 2,289,311 3,388,321
452,058
Unrealized (gains) losses on commodity derivatives 949,967 (4,724,985 ) 231,886 Accretion of asset retirement obligation
604,538 604,511 668,497
Costs to obtain a public listing - 2,935,536 24,592
Increase in value of preferred stock derivative
liability - 15,676,842 26,258,559
Bank mandated commodity derivative novation cost - - 175,000
Amortization of benefit from commodity derivatives
sold - (93,750 ) (72,600 )
Adjusted EBITDA $ 4,293,770 $ 14,975,030 $ 10,405,869
Adjusted EBITDA is used as a supplemental financial measure by our management
and by external users of our financial statements, such as investors, commercial
banks and others, to assess our operating performance compared to that of other
companies in our industry, without regard to financing methods, capital
structure or historical costs basis. It is also used to assess our ability to
incur and service debt and fund capital expenditures.
Our Adjusted EBITDA should not be considered an alternative to net income
(loss), operating income (loss), cash flow provided by (used in) operating
activities or any other measure of financial performance or liquidity presented
in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly
titled measures of another company because all companies may not calculate
Adjusted EBITDA in the same manner. Adjusted EBITDA for the year ended December
31, 2015 decreased from 2014 by $10,681,260 (71.3%). Adjusted EBITDA for the
year ended December 31, 2014 increased from 2013 by $4,569,161 (43.9%).
Interest Expense
Our interest expense for the years ended December 31, 2015, 2014 and 2013, is summarized as follows:
Years Ended December 31,
2015 2014 2013
Interest expense $ 1,439,895 $ 1,385,550 $ 1,599,492
Interest capitalized (983,472 ) (1,059,350 ) (1,031,816 )
Net $ 456,423 $ 326,200 $ 567,676
Bank debt $ 29,800,000 $ 22,900,000 $ 31,215,000
Interest expense increased $54,345 for the year ended December 31, 2015 over the
same period in 2014 as a result of increased borrowings during 2015. Capitalized
interest decreased $75,878 for the year ended December 31, 2015 from the same
period in 2014, driven by a decrease in our unevaluated properties since 2014,
which is the basis of our capitalized interest calculation.
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Interest expense decreased $213,942 for the year ended December 31, 2014 from
the same period in 2013 as a result of debt decreasing in fiscal year 2014 when
net proceeds from the sale of the issuance of the Series A Preferred Stock were
used to pay down debt by $10.4 million during October 2014. Capitalized interest
increased $27,534 for the year ended December 31, 2014 over the same period in
2013 due to an increase in the value of oil and gas properties not subject to
amortization.
For a more complete narrative of interest expense, refer to Note 13 - Debt and
Interest Expense in the Notes to Consolidated Financial Statements included in
this report.
Income Tax Expense
The following summarizes our income tax expense (benefit) and effective tax rates for the years ended December 31, 2015, 2014 and 2013:
Years
Ended December 31,
2015 2014 2013
Consolidated net income (loss) before income taxes $ (18,988,077 ) $ (22,779,004 ) $ (29,969,831 ) Income tax expense (benefit)
(7,983,039 ) (2,553,854 ) 3,080,272
Effective tax rate 42.04% 11.21% (10.28)%
Additionally, differences between the
U.S.
federal statutory rate of 35% and our
effective tax rates are due to the tax effects of the excess of book carrying
value over the tax basis in the full cost pool and the net operating loss
carryforwards for each period. No benefit has been recognized for nondeductible
expenses. Refer to Note 16 - Income Taxes in the Notes to Consolidated Financial
Statements included in this report.
Liquidity and Capital Resources
Our primary and potential sources of liquidity include cash on hand, cash from
operating activities, borrowings under our revolving credit facility, proceeds
from the sales of assets, and potential proceeds from capital market
transactions, including the sale of debt and equity securities. Our cash flows
from operating activities are subject to significant volatility due to changes
in commodity prices, as well as variations in our production. Our business plan
contemplates the potential merger with Davis Petroleum Acquisitions Corp., which
we anticipate will help us with our liquidity and potentially put us in
compliance with our credit facility. While we anticipate the completion of this
merger, we are subject to a number of factors that are beyond our control,
including commodity prices, our bank's determination of our borrowing base which
could impact the merger, production declines, and other factors that could
affect our liquidity and ability to continue as a going concern. Our 2016
business plan includes the capital to drill two wells, a Greater Masters Creek
Field Area proved undeveloped location and another proved undeveloped location
in
Santa Barbara County, California
in the Cat Canyon field once the necessary
permits are approved. Other capital investments are also planned for both
operated and non-operated recompletions, artificial lift upgrades, and
capitalized workovers.
Cash Flows
Our net increase (decrease) in cash for the years ended December, 31, 2015, 2014 and 2013, is summarized as follows:
Years
Ended December 31,
2015 2014 2013
Cash flows provided by (used in) operating activities $ (1,370,144 ) $
24,466,300 $ 14,912,903
Cash flows used in investing activities (12,311,157 ) (18,088,363 ) (27,253,041 )
Cash flows provided by (used in) financing activities 7,478,170 985,874 11,249,627
Net increase (decrease) in cash $ (6,203,131 ) $ 7,363,811 $ (1,090,511 )
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Cash Flows From Operating Activities
Cash flows from operations for the year ended December 31, 2015 decreased by
$25,836,444, or 106%, over fiscal year 2014 primarily due to changes in working
capital, decreased revenues due to low commodity prices, and decreased
production.
Cash flows from operations for the year ended December 31, 2014 increased by
$9,553,397, or 64%, over fiscal year 2013 primarily due to increased working
interest in the La Posada field, new production from the Bertha 8-3 and the
Nettles 39-1, the addition of the
California
production after the merger, and
increased production at the
Crosby
12-1 and Quinn 13-1 wells. These increases
were somewhat mitigated by higher lease operating expenses associated with
increased production.
Cash Flows From Investing Activities
During the year ended December 31, 2015, we had a total of $10,126,307 in oil
and natural gas investing activities. Of that, $4,366,695 was related to
acquisitions of acreage and new properties, which included capitalized G&A and
interest costs of $3.2 million, and approximately $0.77 million of acquisition
costs for additional interest in our
Livingston
and Branville Bay
assets. Drilling and completion activity during the period totaled
$4,219,210. The majority of drilling and completion activity in 2015 is
attributed to the drilling and completion of the Talbot 23-1 well for
$3,181,382, and the completion of the
Blackwell
39-1 and the
Crosby
14-1 wells
for $386,403 and $361,347, respectively. Recompletions, workovers and P&A
activity totaled $1,540,402. Notable projects include installing a gas lift
system in a Masters Creek well for $485,134, installing electrical submersible
pumps (ESP) in two
Livingston Parish
oil wells for $401,200, and re-engineering
production and SWD facilities at Main Pass 4 for $176,825.
During the year ended December 31, 2014, the Greater Masters Creek Field Area
accounted for $18,225,766 of our total oil and natural gas investing activities.
Of that, $16,449,165 was spent to drill and complete the
Crosby
14-1 well and
its related salt water disposal well. The remaining $1,776,601 was spent on
lease-related activities and preliminary costs for the next wells to be drilled
in the field. At the
Livingston
3-D Project, $1,157,071 was spent to drill and
complete the Nettles 39-1 well, along with $1,047,656 to drill the
Blackwell
39-1, which was completed in the first quarter of 2015. Lease-related costs
totaled $484,583. The Talbot 23-1 well in the Amazon 3-D Project was spudded in
early January 2015, and we incurred $364,411 in preliminary costs in
2014. Lease-related costs totaled $732,899. Additionally, $816,970 was spent
evaluating and identifying development opportunities for our new producing
properties in
California
. A net credit of $667,338 for insurance recovery on the
Grief Bros. No. 1 created a credit balance for recompletions, capital workovers
and P&A for the period ended December 31, 2014. During 2013, we realized
proceeds from the sale of interests in our projects and the sale of a salt water
disposal well of $882,666.
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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 through 2017, a
significant deterioration in commodity prices negatively impacts revenues,
earnings, cash flows, capital spending, and 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, sale of
non-strategic assets, and 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.
On December 30, 2015, we entered into the Waiver, Borrowing Base Redetermination
and Ninth Amendment to the credit agreement which provided for a $29.8 million
conforming borrowing base, which will be automatically reduced to $20.0 million
on May 31, 2016 unless otherwise reduced by or to a different number by the
lenders under the credit agreement.
During the year ended December 31, 2015, we sold 46,857 shares of our Series A
Preferred Stock for aggregate net proceeds of $870,386, after deducting
underwriting discounts and offering expenses, and 1,347,458 shares of our common
stock for aggregate gross proceeds of $1,363,160, after deducting underwriting
discounts and offering expenses under our sales agreement. We used the net
proceeds from the offering to fund our capital expenditures and to repay our
debt.
At December 31, 2015, we had a $29.8 million conforming borrowing base with $29.8 million advanced, leaving no available borrowing capacity. The borrowing base will be reduced to $20.0 on May 31, 2016.
Years Ended December 31,
2015 2014 2013
Credit facility:
Balances outstanding, beginning of year $ 22,900,000 $ 31,215,000
$ 17,875,000
Activity 6,900,000 (8,315,000 )
13,340,000
Balances outstanding, end of period $ 29,800,000 $ 22,900,000
$ 31,215,000
Other than the credit facility, we had debt of $263,635 and $282,843 at December
31, 2015 and December 31, 2014, respectively, from installment loans financing
oil and natural gas property insurance premiums. We had a cash balance of
$5,355,191 at December 31, 2015.
We were in breach of the financial covenant in our credit agreement related to
the maximum permitted ratio of funded debt to EBITDA for the fiscal quarters
ended September 30, 2015 and December 31, 2015 as well as our EBITDA to interest
expense covenant at December 31, 2015. We received a waiver of these breaches
pursuant to an amendment to our credit agreement. See Part II, Item 8. Notes to
the Consolidated Financial Statements, Note 3 - Liquidity Considerations.
Credit Facility
We have a credit facility with a syndicate of banks that, as of December 31,
2015, had a borrowing base of $29.8 million through May 31, 2016 and thereafter
the borrowing base will automatically be reduced to $20.0 million unless
otherwise reduced by or to a different amount by the lenders under the credit
agreement, with borrowings of $29.8 million outstanding. The credit agreement
governing our credit facility provides for interest-only payments until May 20,
2017, when the credit agreement matures and any outstanding borrowings are due.
The borrowing base under our credit agreement is subject to regular
redeterminations in the spring and fall of each year, as well as special
redeterminations described in the credit agreement, in each case which may
reduce the amount of the borrowing base.
Our obligations under the credit agreement are guaranteed by our subsidiaries and are secured by liens on substantially all of our assets, including a mortgage lien on oil and natural gas properties having at least 85% of the proved developed reserve value and at least 50% of the proved undeveloped reserve value of the oil and natural gas properties included in the determination of the borrowing base.
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Amounts borrowed under the credit agreement bear interest at either (a) the
LIBOR rate plus 2.25% to 3.75% or (b) the prime rate plus 1.25% to 2.75%,
depending on the amount borrowed under the credit facility. The credit facility
contains a number of covenants that, among other things, restrict, subject to
certain exceptions, our ability to incur additional indebtedness, create liens
on assets, sell certain assets and engage in certain transactions with
affiliates. Additionally, the credit agreement contains a covenant restricting
the payment of dividends on preferred stock if there is less than ten percent
availability on the borrowing base. See Part II, Item 8. Notes to the
Consolidated Financial Statements, Note 3 - Liquidity Considerations and Note 13
- Debt and Interest Expense.
We are subject to certain covenants under the terms of the credit agreement,
which include the maintenance of the following financial covenants determined as
of the last day of each quarter: (1) a ratio of EBITDA to Interest Expense
(which includes dividends as defined in the credit agreement) of not less than
2.75 to 1.0; (2) a ratio of Funded Debt to EBITDA (as defined in the credit
agreement) of not more than 4.0 to 1.0; and (3) a ratio of current assets to
current liabilities of not less than 1.0 to 1.0. As of September 30, 2015, we
were not in compliance with the ratio of Funded Debt to EBITDA and received a
waiver for compliance from our lenders. Further, the waiver also waived any
failure to comply with the above financial covenants as of December 31, 2015, at
which time both the funded debt to EBITDA and the EBITDA to interest
expense ratios were not in compliance. Because the financial covenants are
determined as of the last day of each quarter, the ratios can fluctuate
significantly period to period as the amounts outstanding under the credit
agreement are dependent on the timing of cash flows from operations, capital
expenditures, acquisitions and dispositions of oil and natural gas properties
and securities offerings.
Our credit facility also places restrictions on us and certain of our
subsidiaries with respect to additional indebtedness, liens, dividends and other
payments to shareholders, repurchases or redemptions of our common stock,
payment of cash dividends on our Series A Preferred Stock, investments,
acquisitions, mergers, asset dispositions, transactions with affiliates, hedging
transactions and other matters.
The credit agreement is subject to customary events of default, including in
connection with a change in control. If an event of default occurs and is
continuing, the lenders may elect to accelerate amounts due under the credit
agreement (except in the case of a bankruptcy event of default, in which case
such amounts will automatically become due and payable).
Hedging Activities
Current Commodity Derivative Contracts
We seek to reduce our sensitivity to oil and natural 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
December 31, 2015 December 31, 2014
Oil Natural Gas Oil Natural Gas
Assets
Current $ 2,393,032 $ 265,015 $ 1,851,542 $ 1,486,995
Noncurrent 1,049,661 20,880 1,006,845 396,264
Assets and liabilities are netted within each commodity on the balance sheet as
all contracts are with the same counterparty. For the balances without netting,
refer to Part II, Item 8. Notes to the Consolidated Financial Statements, Note 9
- Commodity Derivative Instruments.
The fair market value of our commodity derivative contracts in place at December
31, 2015 and December 31, 2014 were net assets of $3,728,588 and $4,741,646,
respectively. We sold all of our oil and natural gas options (while retaining
swap contracts) in February 2015 for $4.03 million, accounting for the decrease
in market value from December 31, 2014. New swaps and options contracts were
concurrently initiated for the remainder of 2015 through 2017.
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See Part II, Item 8. Notes to the Consolidated Financial Statements, Note 9 -
Commodity Derivative Instruments, for additional information on our commodity
derivatives.
Hedging commodity prices for a portion of our production is a fundamental part
of our corporate financial management. In implementing our hedging strategy we
seek to:
? effectively manage cash flow to minimize price volatility and generate
internal funds available for operations, capital development projects and
additional acquisitions; and
? ensure our ability to support our exploration activities as well as
administrative and debt service obligations.
Estimating the fair value of derivative instruments requires complex
calculations, including the use of a discounted cash flow technique, estimates
of risk and volatility, and subjective judgment in selecting an appropriate
discount rate. In addition, the calculations use future market commodity prices
which, although posted for trading purposes, are merely the market consensus of
forecasted price trends. The results of the fair value calculation cannot be
expected to represent exactly the fair value of our commodity derivatives. We
currently obtain fair value positions from our counterparties and compare that
value to the calculated value provided by our outside commodity derivative
consultant. We believe that the practice of comparing the consultant's value to
that of our counterparties, who are specialized and knowledgeable in preparing
these complex calculations, reduces our risk of error and approximates the fair
value of the contracts, as the fair value obtained from our counterparties would
be the cost to us to terminate a contract at that point in time.
Commitments and Contingencies
We had the following contractual obligations and commitments as of December 31,
2015:
Asset for Asset
Commodity Operating Retirement
Debt (1) Derivatives (2) Leases Obligations
2016 $ 30,063,635 $ 2,658,047 $ 579,873 $ 70,000
2017 - 1,070,541 564,326 546,284
2018 - - 2,264 3,691,016
2019 - - - 2,273,289
2020 - - - 60,330
Thereafter - - - 2,149,579
Totals $ 30,063,635 $ 3,728,588 $ 1,146,463 $ 8,790,498
(1) Does not include future commitment fees, interest expense or other fees
because our credit agreement is a floating rate instrument, and we cannot
determine with accuracy the timing of future loans, advances, repayments or
future interest rates to be charged.
(2) Represents the estimated future payments under our oil and natural gas
derivative contracts based on the future market prices as of December 31,
2015. 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).
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Critical Accounting Policies and Estimates
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. See
Note 1 - Summary of Significant Accounting Policies in the Notes to the
Consolidated Financial Statements in Part II, Item 8 in this report, for a
discussion of additional accounting policies and estimates made by management.
Accounting Estimates
The preparation of financial statements in accordance with accounting principles
generally accepted in the U. S. ("GAAP") requires us to make estimates and
assumptions that affect the reported amounts of assets and liabilities and the
disclosure of contingent assets and liabilities as of the date of the
consolidated financial statements and the reported amounts of revenues and
expenses during the respective reporting periods. Accounting policies are
considered to be critical if (1) the nature of the estimates and assumptions is
material due to the levels of subjectivity and judgment necessary to account for
highly uncertain matters or the susceptibility of such matters to change, and
(2) the impact of the estimates and assumptions on financial condition or
operating performance is material. Actual results could differ from the
estimates and assumptions used.
Reserve Estimates
Our estimates of proved oil and natural gas reserves constitute those quantities
of oil and natural gas, which, by analysis of geoscience and engineering data,
can be estimated with reasonable certainty to be economically producible from a
given date forward, from known reservoirs, and under existing economic
conditions, operating methods, and government regulations prior to the time at
which contracts providing the right to operate expire, unless evidence indicates
that renewal of such contracts is reasonably certain, regardless of whether
deterministic or probabilistic methods are used for the estimation. Our
engineering estimates of proved oil and natural gas reserves directly impact
financial accounting estimates, including depletion, depreciation and accretion
expense and the full cost ceiling test limitation. At the end of each year, our
proved reserves are estimated by independent petroleum engineers in accordance
with guidelines established by the SEC. These estimates, however, represent
projections based on geologic and engineering data. Reserve engineering is a
subjective process of estimating underground accumulations of oil and natural
gas that are difficult to measure. The accuracy of any reserve estimate is a
function of the quantity and quality of available data, engineering and
geological interpretation and professional judgment. Estimates of economically
recoverable oil and natural gas reserves and future net cash flows necessarily
depend upon a number of variable factors and assumptions, such as historical
production from the area compared with production from other producing areas,
the assumed effect of regulation by governmental agencies, and assumptions
governing future oil and natural gas prices, future operating costs, severance
taxes, development costs and workover costs. The future drilling costs
associated with reserves assigned to proved undeveloped locations may ultimately
increase to the extent that these reserves may be later determined to be
uneconomic and therefore not includable in our reserve calculations. Any
significant variance in the assumptions could materially affect the estimated
quantity and value of the reserves, which could affect the carrying value of our
oil and natural gas properties and/or the rate of depletion of such oil and
natural gas properties.
Disclosure requirements under Staff Accounting Bulletin 113 ("SAB 113") include
provisions that permit the use of new technologies to determine proved reserves
if those technologies have been demonstrated empirically to lead to reliable
conclusions about reserve volumes. The rules also allow companies the option to
disclose probable and possible reserves in addition to the existing requirement
to disclose proved reserves. The disclosure requirements also require companies
to report the independence and qualifications of third party preparers of
reserves and file reports when a third party is relied upon to prepare reserves
estimates. Pricing is based on a 12-month average price using beginning of the
month pricing during the 12-month period prior to the ending date of the balance
sheet to report oil and natural gas reserves. In addition, the 12-month average
is also used to measure ceiling test impairments and to compute depreciation,
depletion and amortization.
Full Cost Method of Accounting
We use the full cost method of accounting for our investments in oil and natural
gas properties. Under this method, all acquisition, exploration and development
costs, including certain related employee costs, incurred for the purpose of
exploring for and developing oil and natural gas are capitalized. Acquisition
costs include costs incurred to purchase, lease or otherwise acquire
property. Exploration costs include the costs of drilling exploratory wells,
including dry hole costs, wells in progress, and geological and geophysical
service costs in exploration activities. Development costs include the costs of
drilling development wells and costs of completions, platforms, facilities and
pipelines. Costs associated with production and general corporate activities are
expensed in the period incurred. Sales of oil and natural gas properties,
whether or not being amortized currently, are accounted for as adjustments of
capitalized costs, with no gain or loss recognized, unless such adjustments
would significantly alter the relationship between capitalized costs and proved
reserves of oil and natural gas.
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The costs associated with unevaluated properties are not initially included in
the amortization base and primarily relate to ongoing exploration activities,
unevaluated leasehold acreage and delay rentals, seismic data and capitalized
interest. These costs are either transferred to the amortization base with the
costs of drilling the related well or are assessed quarterly for possible
impairment or reduction in value.
We compute the provision for depletion of oil and natural gas properties using
the unit-of-production method based upon production and estimates of proved
reserve quantities. Unevaluated costs and related carrying costs are excluded
from the amortization base until the properties associated with these costs are
evaluated. In addition to costs associated with evaluated properties, the
amortization base includes estimated future development costs related to
non-producing reserves. Our depletion expense is affected by the estimates of
future development costs, unevaluated costs and proved reserves, and changes in
these estimates could have an impact on our future earnings.
We capitalize certain internal costs that are directly identified with
acquisition, exploration and development activities. The capitalized internal
costs include salaries, employee benefits, costs of consulting services and
other related expenses and do not include costs related to production, general
corporate overhead or similar activities. We also capitalize a portion of the
interest costs incurred on our debt. Capitalized interest is calculated using
the amount of our unevaluated properties and our effective borrowing rate.
Capitalized costs of oil and natural gas properties, net of accumulated
depreciation, depletion and amortization ("DD&A") and related deferred taxes,
are limited to the estimated future net cash flows from proved oil and natural
gas reserves, discounted at 10 percent, plus the lower of cost or fair value of
unproved properties, as adjusted for related income tax effects (the full cost
ceiling). If capitalized costs exceed the full cost ceiling, the excess is an
impairment charge to income and a write-down of oil and natural gas properties
in the quarter in which the excess occurs.
Given the volatility of oil and natural gas prices, it is probable that our estimate of discounted future net cash flows from estimated proved oil and natural gas reserves will change in the near term.
Future Abandonment Costs
Future abandonment costs include costs to dismantle and relocate or dispose of
our production platforms, gathering systems, wells and related structures and
restoration costs of land and seabed. We develop estimates of these costs for
each of our properties based upon the type of production structure, depth of
water, reservoir characteristics, depth of the reservoir, currently available
procedures and consultations with construction and engineering
consultants. Because these costs typically extend many years into the future,
estimating these future costs is difficult and requires management to make
estimates and judgments that are subject to future revisions based upon numerous
factors, including changing technology, the timing of estimated costs, the
impact of future inflation on current cost estimates and the political and
regulatory environment.
Derivative Hedging Instruments
We seek to reduce our exposure to commodity price volatility by hedging a
portion of our production through commodity derivative instruments. The
estimated fair values of our commodity derivative instruments are recorded in
the Consolidated Balance Sheet. The changes in the fair value of the derivative
instruments are recorded in the Consolidated Statement of Operations and
included in sales of natural gas and crude oil.
Estimating the fair value of derivative instruments requires valuation
calculations incorporating estimates of future NYMEX discount rates and price
movements. The fair value of our commodity derivatives are calculated by our
hedge counterparty and tested by an independent third party utilizing
market-corroborated inputs that are observable over the term of the derivative
contract.
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Derivatives Associated with Preferred Stock
We issued Series A Preferred Stock on July 1, 2011 and Series B Preferred Stock
in July and August of 2012. These shares of preferred stock had provisions with
features of an option or derivative. Therefore, each quarter that these shares
were outstanding required that this derivative liability be marked to fair value
with the resulting changes recorded on the Consolidated Statement of Operations
as "Change in fair value of preferred stock derivative liability - Series A and
Series B." Since we were not public at the time, this determination of fair
value was performed with the use of a
Monte Carlo
option pricing model by an
outside consulting firm using level 3 inputs, along with management estimates of
the probability of various events.
Goodwill
We account for goodwill in accordance with ASC 350, Intangibles-Goodwill and
Other ("ASC 350"). 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. ASC 350 requires that intangible assets with
indefinite lives, including goodwill, be evaluated on an annual basis for
impairment or more frequently if an event occurs 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. We have one reporting unit. Goodwill recorded on our financial statements
is related to the merger with Pyramid in 2014.
Accounting Standards Update ("ASU") No. 2011-08, Testing for Goodwill Impairment
("ASU 2011-08"), simplifies testing for goodwill impairments by allowing
entities to first assess qualitative factors to determine whether the facts or
circumstances lead to the conclusion that it is more likely than not that the
fair value of a reporting unit is less than the carrying value. If the entity
concludes that it is not more likely than not that the fair value of a reporting
unit is less than its carrying value, then the entity does not have to perform
the two-step impairment test. However, if the same conclusion is not reached,
the entity is required to perform the first step of the two-step impairment
test. In this step, the fair value of the reporting unit is calculated and
compared to the carrying value of the reporting unit. If the carrying value
exceeds the fair value, then the entity must perform the second step of the
impairment test to measure the amount of impairment loss, if any. ASU 2011-08
also allows a company to bypass the qualitative assessment and proceed directly
with performing the two-step goodwill impairment test. As a result of the
application of the two-step process during the second quarter of 2015, the
Company determined to write-off the entire goodwill associated with the Pyramid
acquisition of $5.3 million.
Share-based Compensation
We have three types of long-term incentive awards - restricted stock awards
("RSAs"), restricted stock units ("RSUs") and stock appreciation rights
("SARs"). We account for them differently. RSUs are treated as either a
liability or as equity, depending on management's intentions to pay them in
either cash or stock at their vesting date. RSAs are treated as equity since
they are only payable in stock. The associated costs for RSUs are amortized as
stock-based compensation over the life of the award. The costs associated with
the RSAs are amortized either from the point in time when the Company became
public (for RSAs which had a performance-based requirement in order to vest) or
from the time of issuance. SARs are valued at the time of issuance and amortized
over the estimated period they are expected to be outstanding.
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