Introduction
The following is management's discussion and analysis of the significant factors
that affected the Company's financial position and results of operations during
the periods included in the accompanying unaudited consolidated financial
statements. You should read this in conjunction with the discussion under
"Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations" and the audited consolidated financial statements included in our
Annual Report on Form 10-K for the year ended December 31, 2021, and the
unaudited consolidated financial statements included in this quarterly Report.
Certain abbreviations and oil and gas industry terms used throughout this
Quarterly Report are described and defined in greater detail under " Glossary
of Oil And Natural Gas Terms " on page 2 of our Annual Report on Form 10-K for
the year ended December 31, 2021, as filed with the Securities and Exchange
Commission on March 11, 2022.
Our fiscal year ends on December 31st. Interim results are presented on a
quarterly basis for the quarters ended March 31st, June 30th, and September
30th, the first quarter, second quarter and third quarter, respectively, with
the quarter ending December 31st being referenced herein as our fourth quarter.
Fiscal 2022 means the year ended December 31, 2022, whereas fiscal 2021 means
the year ended December 31, 2021.
Certain capitalized terms used below but not otherwise defined, are defined in,
and shall be read along with the meanings given to such terms in, the notes to
the unaudited financial statements of the Company for the three months ended
March 31, 2022, above.
Unless the context requires otherwise, references to the "Company," "we," "us,"
"our," "PEDEVCO" and "PEDEVCO Corp." refer specifically to PEDEVCO Corp. and its
wholly and majority-owned subsidiaries.
In addition, unless the context otherwise requires and for the purposes of this
Report only:
· "Boe" refers to barrels of oil equivalent, determined using the ratio of
one Bbl of crude oil, condensate or natural gas liquids, to six Mcf of
natural gas;
· "Bopd" refers to barrels of oil day;
· "Mcf" refers to a thousand cubic feet of natural gas;
· "NGL" refers to natural gas liquids;
· "Exchange Act" refers to the Securities Exchange Act of 1934, as amended;
· "SEC" or the "Commission" refers to the United States Securities and
Exchange Commission;
· "SWD" means a saltwater disposal well; and
· "Securities Act" refers to the Securities Act of 1933, as amended.
14
Table of Contents
Available Information
The Company's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q,
Current Reports on Form 8-K, and amendments to reports filed pursuant to
Sections 13(a) and 15(d) of the Exchange Act, are filed with the SEC. The
Company is subject to the informational requirements of the Exchange Act and
files or furnishes reports, proxy statements and other information with the SEC.
Such reports and other information filed by the Company with the SEC are
available free of charge at our website (www.pedevco.com) under "Investors" -
"SEC Filings", when such reports are available on the SEC's website. The SEC
maintains an internet site that contains reports, proxy and information
statements, and other information regarding issuers that file electronically
with the SEC at www.sec.gov. The Company periodically provides other information
for investors on its corporate website, www.pedevco.com. This includes press
releases and other information about financial performance, information on
corporate governance and details related to the Company's annual meeting of
shareholders. The information contained on the websites referenced in this Form
10-Q is not incorporated by reference into this filing. Further, the Company's
references to website URLs are intended to be inactive textual references only.
Summary of The Information Contained in Management's Discussion and Analysis of
Financial Condition and Results of Operations
Our Management's Discussion and Analysis of Financial Condition and Results of
Operations (MD&A) is provided in addition to the accompanying consolidated
financial statements and notes to assist readers in understanding our results of
operations, financial condition, and cash flows. Our MD&A is organized as
follows:
? General Overview. Discussion of our business and overall analysis of
financial and other highlights affecting us, to provide context for the
remainder of our MD&A.
? Strategy. Discussion of our strategy moving forward and how we plan to
seek to increase stockholder value.
? Results of Operations and Financial Condition. An analysis of our
financial results comparing the three-month periods ended March 31, 2022,
and 2021, and a discussion of changes in our consolidated balance sheets,
cash flows and a discussion of our financial condition.
? Critical Accounting Policies. Accounting estimates that we believe are
important to understanding the assumptions and judgments incorporated in
our reported financial results and forecasts.
General Overview
We are an oil and gas company focused on the development, acquisition and
production of oil and natural gas assets where the latest in modern drilling and
completion techniques and technologies have yet to be applied. In particular, we
focus on legacy proven properties where there is a long production history, well
defined geology and existing infrastructure that can be leveraged when applying
modern field management technologies. Our current properties are located in the
San Andres formation of the Permian Basin situated in West Texas and eastern New
Mexico and in the Denver-Julesburg Basin in Colorado. As of March 31, 2022, we
held approximately 32,671 net Permian Basin acres located in Chaves and
Roosevelt Counties, New Mexico, through PEDCO and approximately 11,747 net D-J
Basin acres located in Weld and Morgan Counties, Colorado, through our
wholly-owned operating subsidiary, Red Hawk. As of March 31, 2022, we held
interests in 382 gross (303 net) wells in our Permian Basin Asset of which 39
are active producers, 16 are active injectors and two are active Saltwater
Disposal Wells ("SWDs"), all of which are held by PEDCO and operated by its
wholly-owned operating subsidiaries, and interests in 86 gross (22.4 net) wells
in our D-J Basin Asset, of which 18 gross (16.2 net) wells are operated by Red
Hawk and currently producing, 47 gross (5.8 net) wells are non-operated, and 21
wells have an after-payout interest.
Strategy
We believe that horizontal development and exploitation of conventional assets
in the Permian Basin and development of the Wattenberg and Wattenberg Extension
in the D-J Basin, represent among the most economic oil and natural gas plays in
the U.S. We plan to optimize our existing assets and opportunistically seek
additional acreage proximate to our currently held core acreage, as well as
other attractive onshore U.S. oil and gas assets that fit our acquisition
criteria, that Company management believes can be developed using our technical
and operating expertise and be accretive to stockholder value.
15
Table of Contents
Specifically, we seek to increase stockholder value through the following
strategies:
· Grow production, cash flow and reserves by developing our operated
drilling inventory and participating opportunistically in non-operated
projects. We believe our extensive inventory of drilling locations in the
Permian Basin and the D-J Basin, combined with our operating expertise,
will enable us to continue to deliver accretive production, cash flow and
reserves growth. We believe the location, concentration and scale of our
core leasehold positions, coupled with our technical understanding of the
reservoirs will allow us to efficiently develop our core areas and to
allocate capital to maximize the value of our resource base.
· Apply modern drilling and completion techniques and technologies. We own
and intend to acquire additional properties that have been historically
underdeveloped and underexploited. We believe our attention to detail and
application of the latest industry advances in horizontal drilling,
completions design, frac intensity and locally optimal frac fluids will
allow us to successfully develop our properties.
· Optimization of well density and configuration. We own properties that are
legacy oil and gas fields characterized by widespread vertical development
and geological well control. We utilize the extensive petrophysical and
production data of such legacy properties to confirm optimal well spacing
and configuration using modern reservoir evaluation methodologies.
· Maintain a high degree of operational control or build strong
relationships with our operating partners in areas where we do not
operate. We believe that by retaining high operational control and by
building strong partnerships with operators in areas where we do not
operate, we can efficiently manage the timing and amount of our capital
expenditures and operating costs, and thus key in on the optimal drilling
and completions strategies, which we believe will generate higher
recoveries and greater rates of return per well.
· Leverage extensive deal flow, technical and operational experience to
evaluate and execute accretive acquisition opportunities. Our management
and technical teams have an extensive track record of forming and building
oil and gas businesses. We also have significant expertise in successfully
sourcing, evaluating and executing acquisition opportunities. We believe
our understanding of the geology, geophysics and reservoir properties of
potential acquisition targets will allow us to identify and acquire highly
prospective acreage in order to grow our reserve base and maximize
stockholder value.
· Preserve financial flexibility to pursue organic and external growth
opportunities. We intend to maintain a disciplined financial profile in
order to provide us flexibility across various commodity and market
cycles. We intend to utilize our strategic partners and funding which we
expect to be available through the sale of debt or equity, to continuously
fund development and operations.
We also are committed to developing and monitoring environmental, social and
governance ("ESG") initiatives and the Board of Directors plans to evaluate the
potential adoption of ESG initiatives from time to time.
Our strategy is to be the operator and/or a significant working interest owner,
directly or through our subsidiaries and joint ventures, in the majority of our
Permian Basin acreage so we can dictate the pace of development in order to
execute our business plan. Our D-J Basin strategy is to participate in projects
we deem highly economic on an operated or non-operated basis as our acreage
position does not always allow for us to serve as operator in the D-J Basin. Our
net capital expenditures for 2022 are estimated at the time of this Quarterly
Report to range between $35 million to $40 million. This estimate includes
a range of $33 million to $38 million for drilling and completion costs on our
Permian Basin and D-J Basin Assets (of which we have incurred approximately $7.0
million in expenses through March 31, 2022) and approximately $2 million in
estimated capital expenditures for electric submersible pumps ("ESP") purchases,
rod pump conversions, recompletions, well cleanouts, leasing, facilities, and
other miscellaneous capital expenses (of which we have not incurred any expenses
through March 31, 2022). This estimate does not include anything for
acquisitions or other projects that may arise but are not currently anticipated.
We periodically review our capital expenditures and adjust our capital forecasts
and allocations based on liquidity, drilling results, leasehold acquisition
opportunities, proposals from third party operators, and commodity prices, while
prioritizing its financial strength and liquidity.
16
Table of Contents
We plan to continue to evaluate D-J Basin well proposals as received from third
party operators and participate in those we deem most economic and prospective.
If new proposals are received that meet our economic thresholds and require
material capital expenditures, we have flexibility to move capital from our
Permian Asset to our D-J Basin Asset, or vice versa, as our Permian Asset is
100% operated and held by production ("HBP"), allowing for flexibility of timing
on development. Our 2022 development program incorporates an increase in both
basins relating to service cost inflation resulting in an estimated cost
increase of approximately 10 to 15 percent per well, based on costs we have
experienced commencing in the third quarter of 2021 and continuing through the
first quarter of 2022. Our 2022 development program is based upon our current
outlook for the remainder of the year and is subject to revision, if and as
necessary, to react to market conditions, product pricing, contractor
availability, requisite permitting and capital availability, capital allocation
changes between assets, acquisitions, divestitures and other adjustments
determined by the Company in the best interest of its shareholders while
prioritizing our financial strength and liquidity.
We expect that we will have sufficient cash available to meet our needs over the
foreseeable future, including to fund the remainder of our 2022 development
program, discussed above, which cash we anticipate being available from (i)
projected cash flow from our operations, (ii) existing cash on hand, (iii)
equity infusions or loans (which may be convertible) made available from SK
Energy LLC ("SK Energy"), which is 100% owned and controlled by Simon Kukes, our
Chief Executive Officer and director, which funding SK Energy is under no
obligation to provide, (iv) public or private debt or equity financings,
including up to $3.6 million in securities which we may sell in the future in an
on-going "at the market offering", of which no shares have been sold in
connection with to date, and (v) funding through credit or loan facilities. In
addition, we may seek additional funding through asset sales, farm-out
arrangements, and credit facilities to fund potential acquisitions during the
remainder of 2022.
How We Conduct Our Business and Evaluate Our Operations
Our use of capital for acquisitions and development allows us to direct our
capital resources to what we believe to be the most attractive opportunities as
market conditions evolve. We have historically acquired properties that we
believe had significant appreciation potential. We intend to continue to acquire
both operated and non-operated properties to the extent we believe they meet our
return objectives.
We will use a variety of financial and operational metrics to assess the
performance of our oil and natural gas operations, including:
· production volumes;
· realized prices on the sale of oil and natural gas, including the
effects of our commodity derivative contracts;
· oil and natural gas production and operating expenses;
· capital expenditures;
· general and administrative expenses;
· net cash provided by operating activities; and
· net income.
17
Table of Contents
Results of Operations and Financial Condition
Market Conditions and Commodity Prices
Our financial results depend on many factors, particularly the price of natural
gas and crude oil and our ability to market our production on economically
attractive terms. Commodity prices are affected by many factors outside of our
control, including changes in market supply and demand, which are impacted by
among other factors, weather conditions, inventory storage levels, basis
differentials and other factors. As a result, we cannot accurately predict
future commodity prices and, therefore, we cannot determine with any degree of
certainty what effect increases or decreases in these prices will have on our
production volumes or revenues. In addition to production volumes and commodity
prices, finding and developing sufficient amounts of natural gas and crude oil
reserves at economical costs are critical to our long-term success. We expect
prices to remain volatile for the remainder of the year. For information about
the impact of realized commodity prices on our natural gas and crude oil and
condensate revenues, refer to "Results of Operations" below.
Results of Operations
The following discussion and analysis of the results of operations for the
three-month periods ended March 31, 2022 and 2021, should be read in conjunction
with our consolidated financial statements and notes thereto included in this
Quarterly Report on Form 10-Q. The majority of the numbers presented below are
rounded numbers and should be considered as approximate.
Three Months Ended March 31, 2022 vs. Three Months Ended March 31, 2021
We reported net income for the three-month period ended March 31, 2022 of $1.3
million, or $0.02 per share, compared to net income for the three-month period
ended March 31, 2021 of $0.7 million or $0.01 per share. The increase in net
income of $0.6 million, when comparing the current period to the prior year's
period, was primarily due to a $3.6 million increase in net revenues offset by a
$1.2 million increase in total operating expenses and a $1.8 million gain on the
sale of oil and gas properties in the prior period (all of which are discussed
in more detail below).
Net Revenues
The following table sets forth the operating results and production data for the
periods indicated:
Three Months Ended
March 31,
2022 2021 Increase % Increase
Sale Volumes:
Crude Oil (Bbls) 77,768 62,122 15,646 25%
Natural Gas (Mcf) 75,288 32,900 42,388 129%
NGL (Bbls) 6,338 802 5,536 690%
Total (Boe) (1) 96,654 68,407 28,247 41%
Crude Oil (Bbls per day) 864 690 174 25%
Natural Gas (Mcf per day) 837 366 471 129%
NGL (Bbls per day) 70 9 61 678%
Total (Boe per day) (1) 1,074 760 314 41%
Average Sale Price:
Crude Oil ($/Bbl) $ 82.24 $ 55.26 $ 26,98 49%
Natural Gas ($/Mcf) 5.59 2.28 3.31 145%
NGL ($/Bbl) 43.07 28.91 14.16 49%
Net Operating Revenues (in
thousands):
Crude Oil $ 6,396 $ 3,433 $ 2,963 86%
Natural Gas 421 75 346 461%
NGL 273 23 250 1,087%
Total Revenues $ 7,090 $ 3,531 $ 3,559 101%
(1) Assumes 6 Mcf of natural gas equivalents to 1 barrel of oil.
18
Table of Contents
Total crude oil, natural gas and NGL revenues for the three-month period ended
March 31, 2022, increased $3.6 million, or 101%, to $7.1 million, compared to
$3.5 million for the same period a year ago, due to a favorable price variance
of $1.8 million due to the average sales prices for crude oil, natural gas and
NGLs realized by the Company increasing considerably since the three-month
period ended March 31, 2021, which saw average sales prices adversely impacted
by the COVID-19 pandemic, coupled with a favorable volume variance of $1.8
million. The increase in production volume is related to the positive
performance from our participation in non-operated wells in the D-J Basin Asset,
combined with maintaining relatively flat production declines from the existing
operated Permian Basin and D-J Basin Assets.
Operating Expenses and Other Income
The following table summarizes our production costs and operating expenses for
the periods indicated (in thousands):
Three Months Ended
March 31, Increase % Increase
2022 2021 (Decrease) (Decrease)
Direct Lease Operating
Expenses $ 1,033 $ 926 $ 107 12%
Workovers 669 118 551 467%
Other* 654 242 412 170%
Total Lease Operating Expenses $ 2,356 $ 1,286 $ 1,070 83%
Depreciation, Depletion,
Amortization and Accretion $ 1,886 $ 1,561 $ 325 21%
General and Administrative (5%)
(Cash) $ 1,029 $ 1,083 $ (54 )
Share-Based Compensation (18%)
(Non-Cash) 563 684 (121 )
Total General and (10%)
Administrative Expense $ 1,592 $ 1,767 $ (175 )
Gain on Sale of Oil and Gas (100%)
Properties $ - $ 1,805 $ (1,805 )
Interest Expense $ - $ 1 $ (1 ) (100%)
Interest Income $ 3 $ 4 $ (1 ) (25%)
Other Income $ 80 $ 3 $ 77 2,567%
*Includes severance, ad valorem taxes and marketing costs.
Lease Operating Expenses. The increase of $1.1 million was primarily due to
increased workover activity compared to the prior period. In response to the
improved commodity pricing environment, several projects in our Permian Basin
Asset were identified and executed during the three months ended March 31, 2022,
including artificial lift optimizations, artificial lift repairs and well
reactivations. There were also regulatory compliance projects completed, in
accordance with our Permian Basin field wide plan of development during the
three months ended March 31, 2022.
19
Table of Contents
Depreciation, Depletion, Amortization and Accretion. The $0.3 million increase
was primarily the result of an increase in production (noted above) in the
current period when compared to the prior period.
General and Administrative Expenses (excluding share-based compensation). The
decrease of $54,000 in general and administrative expenses (excluding
share-based compensation) was primarily due to the award and payment of a
$250,000 bonus to officers and employees of the Company in the prior period,
whereas a bonus award for officers and employees of the Company was accrued in
the fourth quarter of the prior year, hence no bonus expense was recognized in
the current period; however, the accrued bonus awards in the aggregate amount of
$210,000 were paid out in the current period to our Chief Accounting Officer,
President and Executive Vice President, General Counsel and Secretary, and
additional accrued bonus awards in the aggregate amount of $155,000 were paid
out in the current period to non-officers of the Company. The bonus payroll
decrease was offset by a $159,000 increase in salaries in the current period
compared to the prior period, which was primarily related to a 20% salary
reduction for all the salaried officers and employees that was still in effect
during the prior period, which was put in place to reduce costs at the time that
oil and gas prices were falling as a result of decreased demand due to the
COVID-19 pandemic. The 20% reduction in salaries was returned to prior levels
beginning April 1, 2021, as the Company determined that the oil markets have
recovered to acceptable levels. Additional increases in the current period were
related to $24,000 in additional payroll from officer and employee merit
increases, which were effective as of February 1, 2022, and a $13,000 increase
in other general administrative expenses.
Share-Based Compensation. Share-based compensation, which is included in general
and administrative expenses in the Statements of Operations, decreased by $0.1
million primarily due to the forfeiture of certain employee stock-based options
and nonvested restricted shares due to certain voluntary employee terminations.
Share-based compensation is utilized for the purpose of conserving cash
resources for use in field development activities and operations.
Gain on Sale of Oil and Gas Properties. During the three months ended March 31,
2021, the Company sold rights to 230 net acres and interests in three
non-operated wells located in the D-J Basin for net cash proceeds of $1.9
million and recognized a gain on sale of oil and gas properties of $1.8 million.
The Company had no sales of oil and gas properties during the three months ended
March 31, 2022.
Interest Expense. In the prior period, the $0.01 million interest expense was
due to accrued interest related to the Company's $370,000 loan under U.S. Small
Business Administration's ("SBA") Paycheck Protection Program ("PPP")
established as part of the Coronavirus Aid, Relief and Economic Security Act
("CARES Act"), which was fully forgiven pursuant to the CARES Act in the prior
year. There was no interest expense during the three months ended March 31,
2022.
Interest Income and Other Income. Includes interest earned from our
interest-bearing cash accounts, for which interest rates have remained
relatively flat for both the current and prior periods. Other income in the
current period is primarily related to an $80,000 vendor dispute settlement.
Liquidity and Capital Resources
The primary sources of cash for the Company during the three-month period ended
March 31, 2022 were from $7.1 million in sales of crude oil and natural gas. The
primary uses of cash were funds used for drilling, completion and operating
costs.
20
Table of Contents
Impact of COVID-19
In December 2019, a novel strain of coronavirus, which causes the infectious
disease known as COVID-19, was reported in Wuhan, China. The World Health
Organization declared COVID-19 a "Public Health Emergency of International
Concern" on January 30, 2020, and a global pandemic on March 11, 2020. COVID-19
and the governmental responses thereto significantly reduced worldwide economic
activity during much of 2020, and continues to threaten the global economy, as
variants and mutations of the disease continue to spread, even as vaccines and
boosters have become more widely available. While oil and gas prices have
increased above pre-pandemic levels, it is not possible at this time for the
Company to estimate the full impact that COVID-19 will have on the Company's
business in the future as such estimate would need to be based on whether or not
COVID-19 continues to spread and the effectiveness of the containment of the
virus, by the governments of countries affected and in which the Company
operates. However, the Company's operations have previously been disrupted, and
may be disrupted again in the future due to COVID-19. The COVID-19 outbreak and
mitigation measures have also had an adverse impact on global economic
conditions, as well as an adverse effect on the Company's business and financial
condition and may continue to have an adverse effect on the Company, including
on its potential to conduct financings on terms acceptable to the Company, if at
all. The Company implemented temporary precautionary measures intended to help
minimize the risk of the virus to its employees, vendors, and guests, including
limiting the number of occupants at the Company's Houston headquarters and
requiring all others to work remotely, and discouraged employee attendance at
in-person work-related meetings, which could negatively affect the Company's
business, which measures have recently eased in accordance with federal, state
and local guidance, and the vaccination of substantially all of the Company's
office-based employees. The extent to which the COVID-19 outbreak will continue
to impact the Company's results will depend on future developments that are
highly uncertain and cannot be predicted, including new information that may
emerge concerning the severity of the virus, the continued availability and
efficacy of vaccines and booster shots, the willingness of individuals to be
vaccinated initially, and to obtain booster shots, the effect of virus
mutations, and the actions to contain its impact. Any future decrease in the
price of oil, or the demand for oil and gas, as a result of COVID-19 or
otherwise, will likely have a negative impact on our results of operations and
cash flows.
In response to the effects of COVID-19, the Company has adopted policies,
procedures, and practices both in its Houston office headquarters and across its
field operations to protect its employees, contractors, and guests from
COVID-19, including the adoption of a COVID-19 Response Plan, implementation of
contractor questionnaires to assess COVID-19 risk and exposure prior to entering
any Company facility or worksite, adopting best practices, guidelines and
protocols recommended by the Centers for Disease Control (the "CDC") and the
Office of the Texas Governor for the prevention of exposure and spread of
COVID-19, and evaluating new material developments related to the COVID-19
pandemic and the Company's response thereto at the Company's twice-monthly
management meetings. Given the Company's robust online systems and workflow
practices and procedures, the Company has not experienced any material
challenges or reductions in efficiency or effectiveness of its office-based
workforce, while its field personnel continue to attend to their daily field
operations uninterrupted, while mindful of social distancing and other
preventative measures and safeguards recommended by the CDC, and subject to the
CDC's updated guidance.
We plan to continue to closely monitor the global energy markets and oil and gas
pricing, with the remainder of our 2022 development plan being subject to
revision, if and as necessary, to react to market conditions in the best
interest of its shareholders, while prioritizing its financial strength and
liquidity.
Working Capital
At March 31, 2022, the Company's total current assets of $26.0 million
exceeded its total current liabilities of $6.3 million, resulting in a working
capital surplus of $19.7 million, while at December 31, 2021, the Company's
total current assets of $28.0 million exceeded its total current liabilities of
$5.2 million, resulting in a working capital surplus of $22.8 million. The $3.1
million decrease in our working capital surplus is primarily related to cash
used to fund our current capital drilling budget (described above).
Financing
The Company has an ongoing $3.6 million offering of securities in an "at the
market offering", pursuant to which the Company may sell securities from time to
time (the "ATM Offering"), although no securities have been sold by us to date
in the ATM Offering.
We expect that we will have sufficient cash available to meet our needs over the
foreseeable future, including to fund the remainder of our 2022 development
program, discussed above, which cash we anticipate being available from (i)
projected cash flow from our operations, (ii) existing cash on hand, (iii)
equity infusions or loans (which may be convertible) made available from SK
Energy LLC ("SK Energy"), which is 100% owned and controlled by Simon Kukes, our
Chief Executive Officer and director, which funding SK Energy is under no
obligation to provide, (iv) public or private debt or equity financings,
including up to $3.6 million in securities which we may sell in the future in
the ATM Offering, of which no shares have been sold in connection with to date,
and (v) funding through credit or loan facilities. In addition, we may seek
additional funding through asset sales, farm-out arrangements, and credit
facilities to fund potential acquisitions during the remainder of 2022.
21
Table of Contents
Cash Flows (in thousands)
Three Months Ended March 31,
2022 2021
Cash flows provided by operating activities $ 1,415 $ 913
Cash flows (used in) provided by investing
activities
(5,508 ) 1,289
Cash flows provided by financing activities - 8,303
Net (decrease) increase in cash and restricted
cash $ (4,093 ) $ 10,505
Cash flows provided by operating activities. Net cash provided by operating
activities increased by $0.5 million for the current year's period, when
compared to the prior year's period, primarily due to an increase in net income
of $0.6 million, coupled with a $1.8 million gain on the sale of oil and gas
properties in the prior period, offset by a $0.3 million increase in
depreciation, depletion and amortization and a $2.1 million net decrease to our
other components of working capital (predominantly from our additional oil and
gas sales receivable) in the current period, related to our increased revenue
and operational activity.
Cash flows (used in) provided by investing activities. Net cash used in
investing activities increased by $6.8 million for the current year's period,
when compared to the prior year's period, primarily due to increased capital
spending relating to our drilling and completion activities.
Cash flows provided by financing activities. In the prior period, the Company
closed an underwritten public offering of 5,968,500 shares of common stock at a
public offering price of $1.50 per share, which included the full exercise of
the underwriter's over-allotment option, for net proceeds (after deducting the
underwriters' discount equal to 6% of the public offering price and expenses
associated with the offering) which generated $8.3 million of proceeds, net of
offering costs.
Non-GAAP Financial Measures
We have included EBITDA and Adjusted EBITDA in this Report as supplements to
GAAP measures of performance to provide investors with an additional financial
analytical framework which management uses, in addition to historical operating
results, as the basis for financial, operational and planning decisions and
present measurements that third parties have indicated are useful in assessing
the Company and its results of operations. "EBITDA" represents net income before
interest, taxes, depreciation and amortization. "Adjusted EBITDA" represents
EBITDA, less share based compensation, gain on sale of oil and gas properties,
and accounts payable settlements. Adjusted EBITDA excludes certain items that we
believe affect the comparability of operating results and can exclude items that
are generally non-recurring in nature or whose timing and/or amount cannot be
reasonably estimated. EBITDA and Adjusted EBITDA are presented because we
believe they provide additional useful information to investors due to the
various noncash items during the period. EBITDA and Adjusted EBITDA are also
frequently used by analysts, investors and other interested parties to evaluate
companies in our industry. EBITDA and Adjusted EBITDA have limitations as
analytical tools, and you should not consider them in isolation, or as a
substitute for analysis of our operating results as reported under GAAP. Some of
these limitations are: EBITDA and Adjusted EBITDA do not reflect cash
expenditures, future requirements for capital expenditures, or contractual
commitments; EBITDA and Adjusted EBITDA do not reflect changes in, or cash
requirements for, working capital needs; and EBITDA and Adjusted EBITDA do not
reflect the significant interest expense, or the cash requirements necessary to
service interest or principal payments, on debt or cash income tax payments. For
example, although depreciation and amortization are noncash charges, the assets
being depreciated and amortized will often have to be replaced in the future,
and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such
replacements. Additionally, other companies in our industry may calculate EBITDA
and Adjusted EBITDA differently than PEDEVCO Corp. does, limiting its usefulness
as a comparative measure. You should not consider EBITDA and Adjusted EBITDA in
isolation, or as substitutes for analysis of the Company's results as reported
under GAAP. The Company's presentation of these measures should not be construed
as an inference that future results will be unaffected by unusual or
nonrecurring items. We compensate for these limitations by providing a
reconciliation of each of these non-GAAP measures to the most comparable GAAP
measure. We encourage investors and others to review our business, results of
operations, and financial information in their entirety, not to rely on any
single financial measure, and to view these non-GAAP measures in conjunction
with the most directly comparable GAAP financial measure. The following table
presents a reconciliation of the GAAP financial measure of net income to the
non-GAAP financial measure of Adjusted EBITDA (in thousands):
Three Months Ended March 31,
2022 2021
Net income $ 1,339 $ 728
Add (deduct)
Depreciation, depletion, amortization and
accretion 1,886 1,561
Interest expense - 1
EBITDA 3,225 2,290
Add (deduct)
Share based compensation 563 684
Gain on sale of oil and gas properties - (1,805 )
Accounts payables settlements - (5 )
Adjusted EBITDA $ 3,788 $ 1,164
22
Table of Contents
Critical Accounting Policies
Our discussion and analysis of our financial condition and results of operations
is based on our financial statements, which have been prepared in accordance
with accounting principles generally accepted in the United States. The
preparation of these financial statements requires us to make estimates and
judgments that affect the reported amounts of assets, liabilities, revenues and
expenses. We base our estimates on historical experience and on various other
assumptions that we believe to be reasonable under the circumstances, the
results of which form the basis for making judgments about the carrying values
of assets and liabilities that are not readily apparent from other sources.
Actual results may differ from these estimates under different assumptions or
conditions. We believe the following critical accounting policies affect our
most significant judgments and estimates used in preparation of our financial
statements.
Oil and Gas Properties, Successful Efforts Method. The successful efforts method
of accounting is used for oil and gas exploration and production activities.
Under this method, all costs for development wells, support equipment and
facilities, and proved mineral interests in oil and gas properties are
capitalized. Geological and geophysical costs are expensed when incurred. Costs
of exploratory wells are capitalized as exploration and evaluation assets
pending determination of whether the wells find proved oil and gas reserves.
Proved oil and gas reserves are the estimated quantities of crude oil and
natural gas which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions, (i.e., prices and costs as of the date the
estimate is made). Prices include consideration of changes in existing prices
provided only by contractual arrangements, but not on escalations based upon
future conditions.
Exploratory wells in areas not requiring major capital expenditures are
evaluated for economic viability within one year of completion of drilling. The
related well costs are expensed as dry holes if it is determined that such
economic viability is not attained. Otherwise, the related well costs are
reclassified to oil and gas properties and subject to impairment review. For
exploratory wells that are found to have economically viable reserves in areas
where major capital expenditure will be required before production can commence,
the related well costs remain capitalized only if additional drilling is under
way or firmly planned. Otherwise, the related well costs are expensed as dry
holes.
Exploration and evaluation expenditures incurred subsequent to the acquisition
of an exploration asset in a business combination are accounted for in
accordance with the policy outlined above.
Depreciation, depletion and amortization of capitalized oil and gas properties
is calculated on a field-by-field basis using the unit of production method.
Lease acquisition costs are amortized over the total estimated proved developed
and undeveloped reserves and all other capitalized costs are amortized over
proved developed reserves. Costs specific to developmental wells for which
drilling is in progress or uncompleted are capitalized as wells in progress and
not subject to amortization until completion and production commences, at which
time amortization on the basis of production will begin.
23
Table of Contents
Revenue Recognition. The Company's revenue is comprised entirely of revenue from
exploration and production activities. The Company's oil is sold primarily to
marketers, gatherers, and refiners. Natural gas is sold primarily to interstate
and intrastate natural-gas pipelines, direct end-users, industrial users, local
distribution companies, and natural-gas marketers. NGLs are sold primarily to
direct end-users, refiners, and marketers. Payment is generally received from
the customer in the month following delivery.
Contracts with customers have varying terms, including month-to-month contracts,
and contracts with a finite term. The Company recognizes sales revenues for oil,
natural gas, and NGLs based on the amount of each product sold to a customer
when control transfers to the customer. Generally, control transfers at the time
of delivery to the customer at a pipeline interconnect, the tailgate of a
processing facility, or as a tanker lifting is completed. Revenue is measured
based on the contract price, which may be index-based or fixed, and may include
adjustments for market differentials and downstream costs incurred by the
customer, including gathering, transportation, and fuel costs.
Revenues are recognized for the sale of the Company's net share of production
volumes. Sales on behalf of other working interest owners and royalty interest
owners are not recognized as revenues.
Stock-Based Compensation. Pursuant to the provisions of Financial Accounting
Standards Board ("FASB") Accounting Standards Codification ("ASC") 718,
Compensation - Stock Compensation, which establishes accounting for equity
instruments exchanged for employee service, we utilize the Black-Scholes option
pricing model to estimate the fair value of employee stock option awards at the
date of grant, which requires the input of highly subjective assumptions,
including expected volatility and expected life. Changes in these inputs and
assumptions can materially affect the measure of estimated fair value of our
share-based compensation. These assumptions are subjective and generally require
significant analysis and judgment to develop. When estimating fair value, some
of the assumptions will be based on, or determined from, external data and other
assumptions may be derived from our historical experience with stock-based
payment arrangements. The appropriate weight to place on historical experience
is a matter of judgment, based on relevant facts and circumstances. We estimate
volatility by considering historical stock volatility. We have opted to use the
simplified method for estimating expected term, which is equal to the midpoint
between the vesting period and the contractual term.
Recently Adopted and Recently Issued Accounting Pronouncements. None.
© Edgar Online, source Glimpses