STRATEGIC AIM
TARGETED RESULTS
2021 ANNUAL REPORT
CORPORATE PROFILE
SilverBow Resources, Inc. (“SilverBow” or the “Company”) is a returns-driven,
independent oil and gas company headquartered in Houston, Texas. The Company
is focused on acquiring and developing assets in the Eagle Ford Shale and
Austin Chalk in South Texas. SilverBow’s highly contiguous acreage position of
approximately 150,000 net acres provides for consistent returns spanning all
commodity phase windows of the basin and access to premium Gulf Coast
market pricing. The Company has a broad portfolio mix of high-return locations,
an established track record of execution, and a best-in-class cost structure.
2021 KEY HIGHLIGHTS
$84 MM
ALL-TIME RECORD
FREE CASH FLOW
$53MM
DEBT REDUCTION
YEAR-OVER-YEAR
$234 MM
CASH LIQUIDITY
3X PRIOR YEAR
PRODUCTION & RESERVES
77%
11%
11%
82%
214
MMCFE/D
10%
8%
1,416
BCFE
56%
$1.8
BILLION
44%
PRODUCTION
PROVED RESERVES
PV-10
GAS
OIL
NGL
GAS
OIL
NGL
PDP
PUP
DEAR SHAREHOLDERS:
This past year was defined by our team’s ability
to turn challenges into opportunities.
We weathered severe winter storms, faced continued pandemic disruptions and
navigated the shifting landscape of the global energy economy. SilverBow faced
these challenges head on, delivering record financial and operational performance
while also advancing our “SBOWay” culture focused on safety and employees.
In the first half of the year, SilverBow
By the second half of the year, SilverBow was
moved to our newly designed headquarters.
in position to execute on accretive acquisitions.
We challenged the conventional office setting
We announced two acquisitions in August and
by reimagining our space to provide for a
a third shortly thereafter in October. These
hybrid work environment that promotes
deals bolstered our existing Webb County gas
in-person collaboration and growth while
position, increased our oil production and
supplanting legacy office confines with the
expanded our high-return inventory in the
efficiencies of flexibility and working from home.
Eagle Ford and Austin Chalk.
This was well received by our employees, as
SilverBow was once again named a Top
Workplace in Houston. The adaptability of our
organization allowed us to operate seamlessly
through disruptions posed by the ongoing
pandemic and winter storms alike. Turning
these challenges into opportunity, SilverBow
delivered on high-return projects focused on
Austin Chalk development and oil production
growth both ahead of schedule and under
budget to begin the year, which positioned us
to capture higher commodity prices as
the year progressed.
Taken as a whole, we increased production
by 17% and Adjusted EBITDA by over 50%
year-over-year, generated the most free cash
flow in SilverBow’s history and eclipsed key
balance sheet targets. This was accomplished
by balancing our reinvestment opportunities
with debt pay down, leverage reduction and
liquidity expansion. The market took note of
these positive developments underway,
and SilverBow’s share price increased
more than 300% in 2021.
1.25X
YEAR-END
LEVERAGE RATIO
68%
EBITDA GROWTH
YEAR-OVER-YEAR
60%
REINVESTMENT
RATE
Our Webb County gas and recent
Austin Chalk development will continue to be
a key focus area of long-term growth.
RECORD FREE CASH FLOW
BALANCE SHEET STRENGTH
SilverBow generated more than $80 million
In 2021, SilverBow reduced total debt
of free cash flow in 2021, well above initial
year-over-year by $53 million and cut
expectations entering the year and beating
leverage in half to 1.25x at year-end, down
the previous high of $60 million in 2020.
from 2.50x a year ago. We further improved
Our strategy focused on optimizing returns
our capital structure by extending our Credit
in real-time and, as we progressed through
Facility and Second Lien maturity dates out
the year drilling ahead of schedule and under
to 2024 and 2026, respectively, while also
budget, we adjusted our drilling program to
paying down 25%, or $50 million, of Second
capture additional upside.
Lien principal using cash flow and less
expensive revolver borrowings. Impressively,
our liquidity increased by nearly 3x over the
course of the year to $234 million.
Our cash flow outperformance was driven by
our high quality assets and low cost platform
coinciding with a favorable commodity price
environment. Our Webb County gas and recent
Austin Chalk development will continue to be
a key focus area of long-term growth.
$84
MM
$60.9
MM
2020
2021
38%
INCREASE IN
FREE CASH FLOW
YEAR-OVER-YEAR
FAYETTE
COLORADO
GONZALES
LAVACA
DE WITT
New acquisitions
ATASCOSA
KARNES
significantly
DIMMIT
DIMMIT
LA SALLE
LA SALLE
MCMULLEN
LIVE OAK
LIVE OAK
increased liquids
production.
NEW ACQUISITIONS
WEBB
PLAYING OFFENSE:
ACCRETIVE ACQUISITIONS
By the second half of the year, we had
strengthened our balance sheet considerably
and were well positioned to play offense in the
A&D market. We announced the first of three
accretive acquisitions in early August, which
added dry gas production and high-return
locations in our prolific Webb County Gas area.
The following two acquisitions, announced in
August and October, respectively, significantly
increased our liquids production and added
over five rig-years of inventory.
CORPORATE RESPONSIBILITY
As mentioned, SilverBow led the charge in
developing a hybrid workplace this year by
challenging the conventional, legacy notions
of an office space and responding to our
employees’ feedback. For a second year in a
row, the Company was recognized as a Houston
Top Workplace. Our efforts, however, extended
far beyond just our employees and their work
schedules. In 2021, SilverBow and its employees
made contributions of over $125,000 to the
communities in which we operate through our
“SBOWCares” initiatives, including disaster
All three acquisitions increased our growing
relief assistance for those affected by the winter
portfolio of Austin Chalk locations. SilverBow’s
freeze. We also designated an internal ESG
Austin Chalk wells in 2021 showed some of
Committee to prioritize greater environmental
the strongest returns across our portfolio.
metric reporting and to identify specific,
Additionally, these acquisitions increased our
measurable reduction targets going forward.
cash flow, accelerated our de-leveraging efforts
SilverBow is a low emissions intensity
and added to our reserves base. SilverBow
operator with a relentless commitment to
utilized Company equity as a component of
safe and responsible operations. Reducing
the total purchase price for each of these
emissions and maintaining a low emissions
acquisitions, reflecting confidence from sellers
intensity profile will continue to be a point of
in SilverBow’s ability to develop and operate
emphasis for this organization going forward.
these assets and extract greater overall value.
We expect consolidation to continue in the
Eagle Ford, and SilverBow is positioned to be a
leader on that front as we build upon the positive
momentum made on the A&D front in 2021.
IN SUMMARY AND LOOKING AHEAD
2021 epitomized turning challenge into
Throughout the past year, SilverBow
opportunity. The global economy will be
remained true to its balanced strategy.
faced with the challenge of providing clean,
We balanced re-investment into growth
affordable and reliable energy for generations
with debt and leverage reduction from cash
to come. I am confident that SilverBow is
flows. We balanced our acquisition strategy
better positioned than ever to capitalize
to add both producing assets and high-return
upon this opportunity.
inventory, and we targeted a mix of both oil
and gas commodities. We applied balance
to our workplace vision to combine what
worked in the past while adopting what we
learned from employee feedback, results
and working remotely.
Balance is a cornerstone of our strategy in
the coming year and beyond. SilverBow is
targeting double-digit growth annually while
reinvesting less than 75% of cash flows. This
affords the flexibility to further strengthen
our balance sheet and remain opportunistic
to capture returns either through the drill bit
or through acquisitions. We aim to accomplish
this in the coming year by developing our
runway of core Webb County and Austin
Chalk assets, as well as our recently acquired
liquids-rich assets. We also plan to uphold
the responsibility to our stakeholders,
employees, and communities to achieve these
goals with the highest standards of safety
and environmental consciousness.
A WORD OF THANKS
I would like to take this
opportunity to thank all our
stakeholders, our neighbors
in the communities in which
we operate and our employees
and contractors. SilverBow’s
success is built on the hard
work and dedication of our
team and the trust of our
partners. With challenge comes
opportunity, and SilverBow remains firmly
rooted in improving returns and maximizing
shareholder value.
Thank you,
Sean Woolverton,
Chief Executive Officer
FORM 10-K
STRATEGIC AIM
TARGETED RESULTS
2021 ANNUAL REPORT
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Fiscal Year Ended December 31, 2021
Commission File Number 1-8754
SILVERBOW RESOURCES, INC.
(Exact Name of Registrant as Specified in Its Charter)
Delaware
20-3940661
(State of Incorporation)
(I.R.S. Employer Identification No.)
920 Memorial City Way, Suite 850
Houston, Texas 77024
(281) 874-2700
(Address and telephone number of principal executive offices)
Securities registered pursuant to Section 12(b) of the Act:
Title of Class
Trading Symbol(s)
Exchanges on Which Registered:
Common Stock, par value $0.01 per share
SBOW
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities
Exchange Act of 1934. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period
that the registrant was required to submit such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller
reporting company or an emerging growth company. See definition of “large accelerated filer,” “accelerated filer,” “smaller
Exchange Act.
company”
reporting
company,”
“emerging
in Rule
growth
12b-2
and
the
of
Large accelerated filer
o
Accelerated filer
þ Non-accelerated filer o
Smaller reporting
company
þ
Emerging Growth Company o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period
for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange
Act.
o
1
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the
effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.
7262(b)) by the registered public accounting firm that prepared or issued its audit report. þ
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No þ
The aggregate public float of common equity held by non-affiliates computed by reference to the price at which the common
equity was last sold as quoted on the New York Stock Exchange as of June 30, 2021, the last business day of the second quarter
for fiscal year 2021, was approximately $108,089,448.
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13
or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a
court. Yes þ No o
The number of shares of common stock outstanding as of January 31, 2022 was 16,631,175.
Documents incorporated by reference: Portions of the registrant’s definitive proxy statement for its 2022 annual meeting of
stockholders, to be filed within 120 days after the registrant’s fiscal year end, are incorporated by reference into Part III of this
Annual Report on Form 10-K.
Form 10-K
SilverBow Resources, Inc. and Subsidiary
10-K Part and Item No.
Part I
Items 1 & 2 Business and Properties
Item 1A.
Risk Factors
Item 1B.
Unresolved Staff Comments
Item 3.
Item 4.
Part II
Item 5.
Item 6.
Item 7.
Legal Proceedings
Mine Safety Disclosures
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
[Reserved]
Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Item 9.
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A.
Controls and Procedures
Item 9B.
Other Information
Item 9C.
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Part III
Item 10.
Directors, Executive Officers and Corporate Governance
Item 11.
Executive Compensation
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters
Item 13.
Certain Relationships and Related Transactions, and Director Independence
Item 14.
Principal Accounting Fees and Services
Part IV
Item 15.
Item 16.
Exhibits and Financial Statement Schedules
10-K Summary
Page
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36
37
46
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uncertainty regarding our future operating results; and
other risks and uncertainties described in Item 1A. “Risk Factors,” in this annual report on Form 10-K for the year
•
ended December 31, 2021.
Many of the foregoing risks and uncertainties, as well as risks and uncertainties that are currently unknown to us, are, and
will be, exacerbated by the COVID-19 pandemic and any consequent worsening of the global business and economic
environment. New factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more
of the risks or uncertainties described in this annual report occur, or should underlying assumptions prove incorrect, actual
results and plans could differ materially from those expressed in any forward-looking statements.
All forward-looking statements speak only as of the date they are made. You should not place undue reliance on these
forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the
forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or
expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our
expectations under "Risk Factors" in Item 1A of this annual report on Form 10-K for the year ended December 31, 2021. These
cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are
expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release the results of any revisions
to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to
reflect the occurrence of unanticipated events.
Forward-Looking Statements
This report includes forward-looking statements intended to qualify for the safe harbors from liability established by the
Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of
the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements are based on current
expectations and assumptions and are subject to a number of risks and uncertainties, many of which are beyond our control. All
statements, other than statements of historical fact included in this report, including those regarding our strategy, future
operations, financial position, estimated production levels, expected oil and natural gas pricing, estimated oil and natural gas
reserves or the present value thereof, reserve increases, capital expenditures, budget, projected costs, prospects, plans and
objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,”
“intend,” “estimate,” “budgeted,” “guidance,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar
expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such
identifying words.
Important factors that could cause actual results to differ materially from our expectations include, but are not limited to,
the following risks and uncertainties:
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•
•
•
•
•
•
•
•
•
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•
•
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the severity and duration of world health events, including the COVID-19 pandemic, related economic repercussions,
including disruptions in the oil and gas industry;
actions by the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with
OPEC and other allied producing countries) with respect to oil production levels and announcements of potential
changes in such level;
operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including
logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance
of contracts and supply chain disruptions;
shut-in and curtailment of production due to decreases in available storage capacity or other factors;
volatility in natural gas, oil and NGL prices;
future cash flow and their adequacy to maintain our ongoing operations;
liquidity, including our ability to satisfy our short- or long-term liquidity needs;
our borrowing capacity, future covenant compliance, cash flow and liquidity;
operating results;
asset disposition efforts or the timing or outcome thereof;
ongoing and prospective joint ventures, their structures and substance, and the likelihood of their finalization or the
timing thereof;
the amount, nature and timing of capital expenditures, including future development costs;
timing, cost and amount of future production of oil and natural gas;
impairments on our properties due to lower commodity prices;
availability of drilling and production equipment or availability of oil field labor;
availability, cost and terms of capital;
timing and successful drilling and completion of wells;
availability and cost for transportation of oil and natural gas;
costs of exploiting and developing our properties and conducting other operations;
competition in the oil and natural gas industry;
general economic and political conditions; including political tensions and war;
opportunities to monetize assets;
our ability to execute on strategic initiatives;
effectiveness of our risk management activities including hedging strategy;
environmental liabilities;
counterparty credit risk;
governmental regulation and taxation of the oil and natural gas industry;
developments in world oil and natural gas markets and in oil and natural gas-producing countries;
4
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Items 1 and 2. Business and Properties
As used in this Annual Report on Form 10-K, unless the context otherwise requires or indicates, references to “SilverBow
Resources,” "SilverBow,” “the Company,” “we,” “our,” “ours” and “us” refer to SilverBow Resources, Inc. See pages 30 and
31 for explanations of abbreviations and terms used herein.
Overview
SilverBow Resources is an independent oil and gas company headquartered in Houston, Texas. The Company, originally
founded in 1979, was organized as a Delaware corporation in 2016. SilverBow's strategy is focused on acquiring and
developing assets in the Eagle Ford Shale and Austin Chalk located in South Texas where the Company has assembled
approximately 153,000 net acres across six operating areas. SilverBow's acreage position in each of its operating areas is
highly contiguous and designed for optimal and efficient horizontal well development. The Company believes it has built a
balanced portfolio of properties with a significant base of current production and reserves coupled with low-risk development
drilling opportunities and meaningful upside from newer operating areas.
SilverBow produced an average of 250 million cubic feet of natural gas equivalent per day (“MMcfe/d”) during the fourth
quarter of 2021 and had proved reserves of 1,416 Bcfe (82% natural gas) with a Standardized Measure of $1.6 billion and a
PV-10 of $1.8 billion as of December 31, 2021. PV-10 Value is a non-GAAP measure; see the section titled “Oil and Natural
Gas Reserves” of this Form 10-K for a reconciliation of this non-GAAP measure to the Standardized Measure of discounted
future net cash flow, the most directly comparable GAAP measure.
Being a committed and long-term operator in South Texas, the Company possesses a significant understanding of the
reservoir characteristics, geology, landowners and competitive landscape in the region. SilverBow leverages this in-depth
knowledge to consolidate high quality drilling inventory while continuously enhancing its operations to maximize returns on
capital invested.
Business Strategies
•
•
•
Leverage technical expertise to efficiently develop Eagle Ford Shale drilling locations. As of December 31, 2021, our
technical team has an average of approximately 22 years of experience per person which we believe gives us a technical
advantage when developing and organically expanding our asset base. We leverage this advantage in our existing asset
base to create highly efficient drilling and completion operations. Focusing solely on the Eagle Ford and Austin Chalk
plays allows us to use our operating, technical and regional expertise to interpret geological and operating trends, enhance
production rates and maximize well recovery. We are focused on enhancing asset value through utilizing cost-effective
technology to locate the highest quality intervals to drill and complete oil and gas wells. We continue to optimize our
drilling techniques, shorten our drill times and steer our laterals to target high quality intervals in the Eagle Ford and
Austin Chalk. We have also enhanced fracture stimulation designs, optimizing fluid and proppant usage and fracture stage
spacing. We believe these factors will enhance the return profile of our drilling and completion operations. Our 2022
capital budget range of $180-$200 million (excluding possible future acquisitions) provides for drilling 39 gross (33 net)
horizontal wells which is expected to be funded from operating cash flow.
Prudently grow and maintain balanced inventory of locations. Oil, natural gas and natural gas liquids prices have the
potential to exhibit volatile and unpredictable fluctuations. Further, the timing and duration of such fluctuations are
difficult to predict. As a result, the Company is focused on continuing to expand its liquids-rich inventory through
technical advancements on existing acreage, organic leasing and acquisitions. This strategy of diversification allows us to
pursue our most economic hydrocarbon locations that in turn generate the most compelling returns, with the ability to shift
our focus to locations with different hydrocarbon mixes based on prevailing prices. Given the state of commodity prices in
2021, the Company focused its drilling and completion (“D&C”) program toward both oil and gas development. Of the
373 gross undrilled horizontal locations at year-end 2021, 233 locations are liquids-weighted and 140 locations are gas-
weighted. We assess optimal production timing in response to the market and are agile enough to strategically shift sales
to higher prices periods.
Operate our properties as a low-cost producer. We believe our concentrated acreage position and our experience as an
operator of substantially all of our properties enables us to apply drilling and completion techniques and economies of
scale that improve returns. Operating control allows us to manage pace of development, timing, and associated annual
capital expenditures. Furthermore, we are able to achieve lower operating costs through concentrated infrastructure and
field operations. In addition, our concentrated acreage position allows the Company to drill multiple wells from a single
pad while optimizing lateral lengths. Pad drilling reduces facilities costs and consolidates surface level operations. Our
operational control is critical to our being able to transfer successful drilling and completion techniques and cost cutting
initiatives from one field to another. Finally, we will continue to leverage our proximity to end-user markets of natural gas
which gives us the ability to lower transportation costs relative to other basins and enhance returns to our shareholders.
•
•
Continue to pursue strategic opportunities to further expand our asset base. We continue to take advantage of
opportunities to expand our core position through leasing and acquisitions. We regularly seek to acquire oil and gas
properties that complement our operations, provide exploration and development opportunities, and provide enhanced
cash flow and corporate returns. The Company closed three acquisitions in the second half of 2021. These acquisitions, in
aggregate, added 286 barrels per day of liquids and 4.5 million cubic feet per day to SilverBow’s full year 2021 net
production. This represents less than 3% of the Company's full year 2021 net production. SilverBow expects these
acquisitions to comprise a greater percentage of its full year 2022 net production with a full year's contribution.
In total the Company paid $50.6 million in cash and issued $83.5 million in equity related to these transactions. We plan
to continue strategically targeting certain areas of the Eagle Ford and Austin Chalk where our technical experience and
successful drilling results can be replicated and expanded. We believe our extensive basin-wide experience gives us a
competitive advantage in locating both strategic acquisitions and ground-floor leasing opportunities to expand our core
acreage position in the future.
• Maintain our financial flexibility and liquidity profile. We are committed to preserving our financial flexibility and are
focused on continued growth in a disciplined manner. We have historically funded our capital program by using a
combination of internally generated cash flow, net proceeds from any sales generated through our ATM Program and
funds available on our Credit Facility (Note 4 to the Company's consolidated financial statements in this Form 10-K). As
of December 31, 2021, the Company had $233.0 million in available borrowing capacity under its Credit Facility, which
we believe, along with our projected operating cash flow, provides us with liquidity to execute our 2022 development plan
and opportunistically acquire or lease additional acreage. Our Credit Facility and Second Lien (Note 4 to the Company's
consolidated financial statements in this Form 10-K), maturing in April 2024 and December 2026, respectively, are our
only debt maturities.
• Manage risk exposure. We utilize a disciplined hedging program to limit our exposure to volatility in commodity prices
and achieve a more predictable level of cash flow to support current and future capital expenditure plans. Our multi-year
price risk management program also includes hedges to limit our basis differential to oil and natural gas pricing. We take
a systematic approach to hedging and periodically add hedges to our portfolio in an effort to protect the rates of returns on
our drilling program. As of February 25, 2022, we had approximately 62% of total production volumes hedged for full
year 2022, using the midpoint of the Company's production guidance of 235 - 255 MMcfe/d.
Our Competitive Strengths
•
•
•
Inventory of drilling locations with high degree of operational control. We have developed a significant inventory of
future drilling locations. As of December 31, 2021, we had approximately 153,000 net acres in the Eagle Ford and Austin
Chalk and 373 gross horizontal drilling locations. Approximately 54% of our estimated proved reserves at December 31,
2021 were undeveloped. We operate essentially all of our proved reserves and have an average working interest of
approximately 81% across our identified locations. These factors provide us with a high level of control over our
operations, allowing us to manage our development drilling schedule, utilize pad drilling where applicable, and implement
leading edge modern completion techniques. We plan to continue to deliver production, reserve and cash flow growth by
developing our extensive inventory of low-risk drilling locations in a disciplined manner.
Ability to adjust cadence and hydrocarbon mix of operations activity. In 2021, we drilled 18 net wells, completed 24 net
wells and brought 24 net wells online. SilverBow completed its planned drilling and completion activity in the first
quarter of 2021, primarily comprised of Webb County Gas wells drilled in late 2020. During the first quarter of 2021,
SilverBow released its one drilling rig as part of a budgeted pause in development activity to assess current market
conditions at such time. Accordingly, based on management's outlook at such time, SilverBow adjusted the timing and
scope of its mid-year 2021 liquids development to start earlier and drill additional wells. The ability to adjust our drilling
and completion schedule in response to management's real-time outlook and view of commodity prices allows us to focus
on the highest return, lowest risk projects.
Proximity to Demand Centers. Our assets are positioned in one of the most economically advantaged natural gas and oil
regions of North America. Our proximity to the Gulf Coast affords us much lower commodity basis differentials and
meaningfully higher price realizations when compared to other domestic basins. For instance, in 2021 our average natural
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•
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•
gas basis differentials to NYMEX were $0.58/Mcf premium versus $0.34/Mcf discount for the Permian Basin index into
the El Paso pipeline. Additionally, our assets are in close proximity to the largest and highest growth natural gas and NGL
demand centers, including increasing LNG exports, natural gas exports to Mexico and industrial, petrochemical, and
power demand in the Gulf Coast markets.
Experienced and proven technical team. As of December 31, 2021, we employed 13 oil and gas technical professionals,
including geoscientists, drilling, completion, production and reservoir engineers, and other oil and gas professionals who
collectively have an average of approximately 22 years of experience in their technical fields. Our senior technical team
has come from a number of large and successful organizations. Our technical team is focused on utilizing modern
completion techniques to increase our estimated ultimate recovery and maximize our per-well returns. Our enhanced
completion designs include tighter fracture stage spacing as well as optimized proppant loadings and intensity.
Additionally, we rely on advanced technologies to better define geologic risk and enhance the results of our drilling
efforts. We continually apply our extensive in-house experience and current technologies to benefit our drilling and
production operations.
Proven low cost operator with contiguous acreage. Our core acreage positions are contiguous in nature which allows us to
continue to lower per unit costs through drilling longer laterals, utilizing pad drilling, consolidating in-field infrastructure,
and efficiently sourcing materials through our procurement strategies. We believe the nature of our positions and our
operational improvements and efficiencies will allow us to continue to successfully mitigate service cost inflation.
Additionally, we continually seek to optimize our production operations with the objective of reducing our operating costs
through efficient well management. Finally, our significant operational control, as well as our manageable leasehold
drilling obligations, provide us the flexibility to control our costs.
Balance Sheet discipline and sufficient liquidity. As of December 31, 2021, the Company had $233.0 million in available
borrowing capacity under our Credit Facility, which we believe, along with our operating cash flow, provides us with a
sufficient amount of liquidity to execute our 2022 development plan and opportunistically acquire or lease additional
acreage even with modest changes in the commodity environment. Our Credit Facility and Second Lien, maturing in April
2024 and December 2026, respectively, are our only debt maturities. As of December 31, 2021, we had $227.0 million
drawn on our $460.0 million borrowing base under the Credit Facility. We prudently lowered our leverage profile to a
conservative level in 2021 allowing us to continue to operate with balance sheet discipline.
Property Overview
SilverBow's operations are focused in six fields located in the Eagle Ford and Austin Chalk located in South Texas. The
following table sets forth information regarding its Eagle Ford and Austin Chalk fields in 2021:
Fields
Artesia
AWP
Fasken
Atascosa
Eastern Eagle Ford
Southern Eagle Ford Gas
Other (1)
Total
(1) Other includes non-core properties
Net Acreage
2021
Production
(Mcfe/d)
Gas as % of
2021
Production
2021 Net Wells
Drilled
2021 Net Wells
Completed
12,105
53,078
10,083
4,947
19,768
36,800
16,325
153,106
48,964
25,237
117,652
723
1,246
18,448
1,739
214,009
40 %
37 %
100 %
9 %
26 %
99 %
25 %
77 %
9
1
6
—
—
—
2
18
9
1
12
—
—
—
2
24
The following table sets forth information regarding the Company's 2021 year-end proved reserves of 1,415.8 Bcfe and
production of 78.1 Bcfe by area:
Proved
Developed
Reserves
(Bcfe)
Proved
Undeveloped
Reserves
(Bcfe)
Total Proved
Reserves
(Bcfe)
% of Total
Proved
Reserves
Oil and
NGLs as %
of Proved
Reserves
Total
Production
(Bcfe)
133.4
64.3
364.2
5.0
24.7
58.7
8.0
55.2
64.0
581.7
38.4
18.2
—
—
188.6
128.3
945.9
43.4
42.9
58.7
8.0
13.3 %
9.1 %
66.8 %
3.1 %
3.0 %
4.1 %
0.6 %
658.3
757.5
1,415.8
100.0 %
54.6 %
66.6 %
— %
92.5 %
69.4 %
0.7 %
21.1 %
18.4 %
17.9
9.2
42.9
0.3
0.5
6.7
0.6
78.1
Fields
Artesia
AWP
Fasken
Atascosa
Eastern Eagle Ford
Southern Eagle Ford Gas
Other (1)
Total
(1) Other includes non-core properties
Oil and Natural Gas Reserves
The following tables present information regarding proved oil and natural gas reserves attributable to SilverBow's
interests in proved properties as of December 31, 2021, 2020 and 2019. The information set forth in the tables regarding
reserves is based on proved reserves reports prepared in accordance with Securities and Exchange Commission’s (“SEC”)
rules. H.J. Gruy and Associates, Inc. (“Gruy”), independent petroleum engineers, prepared the Company's proved reserves
reports as of December 31, 2021, 2020 and 2019.
The reserves estimation process involves members of the reserves and evaluation department who report to the Chief
Reservoir Engineer. The staff includes engineers whose duty is to prepare estimates of reserves in accordance with the SEC's
rules, regulations and guidelines. This team worked closely with Gruy to ensure the accuracy and completeness of the data
utilized for the preparation of the 2021, 2020 and 2019 reserve reports. All information from SilverBow's secure engineering
database as well as geographic maps, well logs, production tests and other pertinent data were provided to Gruy.
The Chief Reservoir Engineer supervises this process with multiple levels of review and reconciliation of reserve
estimates to ensure they conform to SEC guidelines. Reserves data are also reported to and reviewed by senior management
quarterly. The Board of Directors (the “Board”) reviews the reserve data periodically and the independent Board members
meet with Gruy in executive sessions at least annually.
The technical person at Gruy primarily responsible for overseeing preparation of the 2021, 2020 and 2019 reserves report
and the audits of prior year reports is a Licensed Professional Engineer, holds a degree in petroleum engineering, is past
Chairman of the Gulf Coast Section of the Society of Petroleum Engineers, is past President of the Society of Petroleum
Evaluation Engineers, and has over 30 years of experience in preparing reserves reports and overseeing reserves audits.
The Company's Chief Reservoir Engineer, the primary technical person responsible for overseeing the preparation of its
2021, 2020 and 2019 reserve estimates, holds a bachelor's degree in geology, is a member of the Society of Petroleum
Engineers and the Society of Professional Well Log Analysts, and has over 25 years of experience in petrophysical analysis,
reservoir engineering, and reserves estimation.
Estimates of future net revenues from SilverBow's proved reserves, Standardized Measure and PV-10 (PV-10 is a non-
GAAP measure defined below), as of December 31, 2021, 2020 and 2019 are made in accordance with SEC criteria, which is
based on the preceding 12-months' average adjusted price after differentials based on closing prices on the first business day of
each month (excluding the effects of hedging) and are held constant for that year's reserves calculation throughout the life of
the properties, except where such guidelines permit alternate treatment, including, in the case of natural gas contracts, the use
of fixed and determinable contractual price escalations. The Company has interests in certain tracts that are estimated to have
additional hydrocarbon reserves that cannot be classified as proved and are not reflected in the following tables.
The following prices were used to estimate SilverBow's SEC proved reserve volumes, year-end Standardized Measure and
PV-10. The 12-month 2021 average adjusted prices after differentials were $3.75 per Mcf of natural gas, $63.98 per barrel of
oil, and $25.29 per barrel of NGL, compared to $2.13 per Mcf of natural gas, $37.83 per barrel of oil, and $11.66 per barrel of
NGL for 2020 and $2.62 per Mcf of natural gas, $58.37 per barrel of oil, and $16.83 per barrel of NGL for 2019.
8
9
As noted above, PV-10 Value is a non-GAAP measure. The most directly comparable GAAP measure to the PV-10 Value
is the Standardized Measure. The Company believes the PV-10 Value is a useful supplemental disclosure to the Standardized
Measure because the PV-10 Value is a widely used measure within the industry and is commonly used by securities analysts,
banks and credit rating agencies to evaluate the value of proved reserves on a comparative basis across companies or specific
properties without regard to the owner's income tax position. SilverBow uses the PV-10 Value for comparison against its debt
balances, to evaluate properties that are bought and sold and to assess the potential return on investment in its oil and gas
properties. PV-10 Value is not a measure of financial or operating performance under GAAP, nor should it be considered in
isolation or as a substitute for any GAAP measure. The Company's PV-10 Value and the Standardized Measure do not purport
to represent the fair value of SilverBow's proved oil and natural gas reserves.
The following table provides a reconciliation between the Standardized Measure (the most directly comparable financial
measure calculated in accordance with U.S. GAAP) and PV-10 Value of the Company's proved reserves:
(in millions)
As of December 31,
2021
2020
Standardized Measure of Discounted Future Net Cash Flows
$
1,558 $
513 $
Adjusted for: Future income taxes (discounted at 10%)
PV-10 Value
259
13
$
1,817 $
526 $
2019
868
108
976
The following tables set forth estimates of future net revenues presented on the basis of unescalated prices and costs in
accordance with criteria prescribed by the SEC and presented on a Standardized Measure and PV-10 basis as of December 31,
2021, 2020 and 2019. Operating costs, development costs, asset retirement obligation costs, and certain production-related
taxes were deducted in arriving at the estimated future net revenues.
At December 31, 2021, SilverBow had estimated proved reserves of 1,416 Bcfe with a Standardized Measure of $1.6
billion and PV-10 Value of $1.8 billion. This is an increase of approximately 309 Bcfe from the Company's year-end 2020
proved reserves quantities primarily due to increases in our natural gas reserves primarily from our Austin Chalk area along
with acquisitions. SilverBow's total proved reserves at December 31, 2021 were approximately 10% crude oil, 82% natural
gas, and 8% NGLs, while 46% of its total proved reserves were developed. Essentially all of the Company's proved reserves
are located in Texas. The following amounts shown in MMcfe below are based on an oil and natural gas liquids conversion
factor of 1 Bbl to 6 Mcf:
Estimated Proved Natural Gas, Oil and NGL Reserves
2021
As of December 31,
2020
Natural gas reserves (MMcf):
Proved developed
Proved undeveloped
Total
Oil reserves (MBbl):
Proved developed
Proved undeveloped
Total
NGL reserves (MBbl):
Proved developed
Proved undeveloped
Total
525,737
629,643
1,155,380
9,692
14,606
24,298
12,390
6,710
19,100
415,390
532,704
948,094
6,963
5,569
12,532
8,164
5,692
13,855
2019
478,005
680,347
1,158,352
6,476
10,592
17,068
10,377
16,236
26,614
Total Estimated Reserves (MMcfe)
(1)
1,415,771
1,106,415
1,420,439
Standardized Measure of Discounted Future Net Cash Flows (in
millions) (2)
$
1,558 $
513 $
868
PV-10 by reserve category
Proved developed
Proved undeveloped
Total PV-10 Value (2)
(1) The reserve volumes exclude natural gas consumed in operations.
(2) The Standardized Measure and PV-10 Values as of December 31, 2021, 2020 and 2019 are net of $3.5 million, $2.2 million and $1.7 million of plugging
and abandonment costs, respectively.
1,031 $
786
1,817 $
382 $
144
526 $
635
341
976
$
$
Proved reserves are estimates of hydrocarbons to be recovered in the future. Reserves estimation is a subjective process of
estimating the sizes of underground accumulations of oil and natural gas that cannot be measured in an exact way. The
accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation
and judgment. Reserves reports of other engineers might differ from the reports contained herein. Results of drilling, testing,
and production subsequent to the date of the estimate may justify revision of such estimates. Future prices received for the sale
of oil and natural gas may be different from those used in preparing these reports. The amounts and timing of future operating
and development costs may also differ from those used. Accordingly, reserves estimates are often different from the quantities
of oil and natural gas that are ultimately recovered. There can be no assurance that these estimates are accurate predictions of
the present value of future net cash flow from oil and natural gas reserves.
10
11
Proved Undeveloped Reserves
Oil and Gas Wells
The following table sets forth the aging of SilverBow's proved undeveloped reserves as of December 31, 2021:
Volume
(Bcfe)
% of PUD
Volumes % of PV-10
Year Added
2021
2020
2019
2018
2017
Total
479.3
77.5
130.6
40.0
30.1
757.5
63 %
10 %
17 %
5 %
5 %
100 %
65 %
8 %
17 %
6 %
4 %
100 %
During 2021, the Company's proved undeveloped reserves increased by approximately 157.3 Bcfe primarily due to
increases in our natural gas reserves from acquisitions of approximately 166.1 Bcfe and extensions of 313.2 Bcfe. The
increases were partially offset by removals and negative revisions of approximately 198.7 Bcfe. Further, SilverBow incurred
approximately $58.0 million in capital expenditures (excluding acquisitions) during the year which resulted in the conversion
of 123.3 Bcfe of its December 31, 2020 proved undeveloped reserves to proved developed reserves, primarily in our Artesia
and Fasken fields. During 2020, the Company's proved undeveloped reserves decreased by approximately 241.1 Bcfe
primarily due to the removal of undeveloped reserves mainly in SilverBow's AWP and Southern Eagle Ford fields as a result
of the reduction in our planned capital activity.
The PV-10 Value from the Company's proved undeveloped reserves was $786.4 million at December 31, 2021, which
was approximately 43% of its total PV-10 Value of $1.8 billion.
Sensitivity of Reserves to Pricing
As of December 31, 2021, a 5% increase in natural gas pricing would increase SilverBow's total estimated proved
reserves by approximately 1.9 Bcfe and would increase the PV-10 Value by approximately $91.4 million. Similarly, a 5%
decrease in natural gas pricing would decrease the Company's total estimated proved reserves by approximately 2.0 Bcfe and
would decrease the PV-10 Value by approximately $92.0 million.
As of December 31, 2021, a 5% increase in oil and NGL pricing would increase SilverBow's total estimated proved
reserves by approximately 1.7 Bcfe, and would increase the PV-10 Value by approximately $52.9 million. Similarly, a 5%
decrease in oil and NGL pricing would decrease the Company's total estimated proved reserves by approximately 1.9 Bcfe and
would decrease the PV-10 Value by approximately $53.0 million.
This sensitivity analysis is as of December 31, 2021 and, accordingly, does not consider drilling and completion activity,
acquisitions or dispositions of oil and gas properties, production, changes in oil, natural gas and natural gas liquids prices, and
changes in development and operating costs occurring subsequent to December 31, 2021 that may require revisions to
estimates of proved reserves.
The following table sets forth the total gross and net wells in which SilverBow owned an interest at the following dates:
December 31, 2021
Gross (1)
Net
December 31, 2020
Gross (1)
Net
December 31, 2019
Gross (1)
Net
Oil Wells
Gas Wells
Total
Wells(1)
174
145.9
103
100.9
95
93.0
352
279.6
266
216.9
246
198.8
526
425.5
369
317.8
341
291.8
(1) Excludes 8, 8, and 4 service wells in 2021, 2020 and 2019, respectively.
Oil and Gas Acreage
The following table sets forth the developed and undeveloped leasehold acreage held by the Company at December 31,
2021:
Texas (1)
Louisiana
Wyoming
Total
Developed
Undeveloped
Gross
Net
Gross
Net
103,820
5,084
—
108,904
90,528
4,775
—
95,303
66,052
4,795
1,596
72,443
62,577
4,403
1,147
68,127
(1) The Company's total Texas acreage is located in the Eagle Ford field.
As of December 31, 2021, SilverBow's net undeveloped acreage in Texas subject to expiration, if not renewed, is
approximately 81% in 2022, 13% in 2023, 2% in 2024 and 4% in 2025 and thereafter. In our core areas, acreage scheduled to
expire can be held through drilling operations or SilverBow can exercise extension options. The exploration potential of all
undeveloped acreage is fully evaluated before expiration. In each fiscal year where undeveloped acreage is subject to
expiration, our intent is to reduce the expirations through either development or extensions, if we believe it is commercially
advantageous to do so.
12
13
Drilling and Other Exploratory and Development Activities
Marketing of Production
The following table sets forth the results of the Company's drilling and completion activities during the years ended
December 31, 2021, 2020 and 2019:
Year
Type of Well
Total
Gross Wells
Producing
Dry
Total
Net Wells
Producing
Dry
2021
Exploratory
Development
2020
Exploratory
Development
2019
Exploratory
Development
—
21
—
19
—
30
—
—
21 —
—
—
19 —
—
30
—
—
—
18.7
—
14.8
—
27.7
—
—
18.7
—
—
—
14.8
—
—
—
27.7
—
Recent Activities
As of December 31, 2021, SilverBow was in the process of drilling one well in our La Mesa field where we have an 100%
working interest. This well was completed in the first quarter of 2022.
Operations
The Company generally seeks to be the operator of the wells in which it has a significant economic interest. As operator,
SilverBow designs and manages the development of a well and supervises operation and maintenance activities on a day-to-
day basis. The Company does not own drilling rigs or other oil field services equipment used for drilling or maintaining wells
on properties it operates. Independent contractors supervised by SilverBow provide this equipment and personnel. The
Company employs drilling, production and reservoir engineers, geoscientists, and other specialists who work to improve
production rates, increase reserves, and lower the cost of operating SilverBow's oil and natural gas properties.
Operations on the Company's oil and natural gas properties are customarily accounted for in accordance with Council of
Petroleum Accountants Societies' guidelines. SilverBow charges a monthly per-well supervision fee to the wells it operates
including its wells in which it owns up to a 100% working interest. Supervision fees vary widely depending on the geographic
location and depth of the well and whether the well produces oil or natural gas. The fees for these activities in 2021 totaled
$5.1 million and ranged from $125 to $1,704 per well per month.
The Company typically sells its oil and natural gas production at market prices near the wellhead or at a central point after
gathering and/or processing. SilverBow usually sells its natural gas in the spot market on a seasonal or monthly basis, while it
sells its oil at prevailing market prices. The Company does not refine any oil it produces. For the years ended December 31,
2021 and 2020, parties which accounted for approximately 10% or more of SilverBow's total oil and gas receipts were as
follows:
Purchasers greater than 10%
Kinder Morgan
Plains Marketing
Twin Eagle
Trafigura
Shell Trading
*Oil and gas receipts less than 10%
Year Ended
December 31, 2021
Year Ended
December 31, 2020
26 %
10 %
15 %
16 %
12 %
19 %
17 %
17 %
13 %
*
The Company has gas processing and gathering agreements with Southcross Energy for a majority of SilverBow's natural
gas production in the AWP area. Oil production is transported to market by truck and sold at prevailing market prices.
The Company has a gas gathering agreements with Howard Energy Partners providing for the transportation of
SilverBow's Eagle Ford and Austin Chalk production on the pipeline from our Fasken, Rio Bravo and La Mesa areas to the
Kinder Morgan Texas Pipeline, Eagle Ford Midstream or Howard's Impulsora Pipeline (Nueva Era), where it is sold at prices
tied to monthly and daily natural gas price indices. At Fasken, the Company also has a connection with the Navarro gathering
system into which it may deliver natural gas from time to time.
SilverBow has an agreement with Eagle Ford Gathering LLC that provides for the gathering and processing for almost all
of its natural gas production in the Artesia area. Natural gas in the area can also be delivered to the Targa system for
processing and transportation to downstream markets. In the Artesia area, the Company's oil production is sold at prevailing
market prices and transported to market by truck.
The prices in the tables below do not include the effects of hedging. Quarterly prices are detailed under “Results of
Operations – Revenues” in “Management's Discussion and Analysis of Financial Condition and Results of Operations” in this
Form 10-K.
The following table summarizes production volumes, sales prices, and production cost information for SilverBow's net oil,
NGL and natural gas production for the years ended December 31, 2021, 2020 and 2019:
All Fields
Year Ended December 31,
2020
2019
2021
Net Production Volume:
Oil (MBbls)
Natural gas liquids (MBbls)
Natural gas (MMcf)
Total (MMcfe)
Average Sales Price:
Oil (Per Bbl)
Natural gas liquids (Per Bbl)
Natural gas (Per Mcf)
Total (Per Mcfe)
Average Production Cost (Per Mcfe sold) (1)
1,462
1,472
60,510
78,113
1,521
1,114
50,988
66,800
$
$
$
$
$
67.46 $
27.78 $
4.42 $
5.21 $
37.89 $
13.02 $
2.06 $
2.66 $
0.66 $
0.63 $
1,605
1,717
64,388
84,320
57.84
14.70
2.65
3.42
0.57
(1) Average production cost includes lease operating costs, transportation and gas processing costs but excludes severance and ad valorem taxes.
14
15
The following table provides a summary of the Company's production volumes, average sales prices, and average
production costs for its fields with proved reserves greater than 15% of total proved reserves. This field, which is inclusive of
our Fasken, La Mesa and Rio Bravo fields, accounts for approximately 67% of SilverBow's proved reserves based on total
MMcfe as of December 31, 2021:
Fasken
Year Ended December 31,
2020
2019
2021
Net Production Volume:
Natural gas liquids (MBbls)
Natural gas (MMcf) (1)
Total (MMcfe)
Average Sales Price:
Natural gas liquids (Per Bbl)
Natural gas (Per Mcf)
Total (Per Mcfe)
Average Production Cost (Per Mcfe sold)
(2)
2
42,933
42,943
2
35,399
35,410
$
$
$
$
24.55 $
4.53 $
4.53 $
10.41 $
2.03 $
2.03 $
0.56 $
0.56 $
2
38,195
38,206
14.13
2.65
2.65
0.60
(1) Excludes natural gas consumed in operations.
(2) Average production cost includes lease operating costs, transportation and gas processing costs but excludes severance and ad valorem taxes.
Risk Management
The Company's operations are subject to all of the risks normally incident to the exploration for and the production of oil
and natural gas, including blowouts, pipe failure, casing collapse, fires, and adverse weather conditions (including conditions
exacerbated by climate change), each of which could result in severe damage to or destruction of oil and natural gas wells,
production facilities or other property, or individual injuries. The oil and natural gas exploration business is also subject to
environmental hazards, such as oil and produced water spills, natural gas leaks, and ruptures and discharges of toxic
substances or gases that could expose SilverBow to substantial liability due to pollution and other environmental damage. The
Company maintains comprehensive insurance coverage, including general liability insurance, operators extra expense
insurance, and property damage insurance. SilverBow's standing Insurable Risk Advisory Team, which includes individuals
from operations, drilling, facilities, legal, health safety and environmental and finance departments, meets regularly to evaluate
risks, review property values, review and monitor claims, review market conditions and assist with the selection of coverages.
The Company believes that its insurance is adequate and customary for companies of a similar size engaged in comparable
operations, but if a significant accident or other event occurs that is uninsured or not fully covered by insurance, it could
adversely affect SilverBow. Refer to “Item 1A. Risk Factors” of this Form 10-K for more details and for discussion of other
risks.
Commodity Risk
The oil and gas industry is affected by the volatility of commodity prices. Realized commodity prices received for such
production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. The
Company has derivative instruments in place to protect a significant portion of its production against declines in oil and
natural gas prices through the fourth quarter of 2023. We believe SilverBow also has sufficient protection in place to protect
against volatility in natural gas liquids prices through the fourth quarter of 2022. For additional discussion related to the
Company's price-risk policy, refer to Note 5 of the consolidated financial statements in this Form 10-K.
Competition
SilverBow operates in a highly competitive environment, competing with major integrated and independent energy
companies for desirable oil and natural gas properties, as well as for equipment, labor, and materials required to develop and
operate such properties. Many of these competitors have financial and technological resources substantially greater than the
Company's. The market for oil and natural gas properties is highly competitive and SilverBow may lack technological
information or expertise available to other bidders. The Company may incur higher costs or be unable to acquire and develop
desirable properties at costs SilverBow considers reasonable because of this competition. The Company's ability to replace and
expand its reserve base depends on its continued ability to attract and retain quality personnel and identify and acquire suitable
producing properties and prospects for future drilling and acquisition.
Environmental and Occupational Health and Safety Matters
SilverBow's business operations are subject to numerous federal, state and local environmental and occupational health
and safety laws and regulations. Numerous governmental entities, including the U.S. Environmental Protection Agency
(“EPA”), the U.S. Occupational Safety and Health Administration (“OSHA”) and analogous state agencies, have the power to
enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly
actions. These laws and regulations may, among other things (i) require the acquisition of permits to conduct drilling and other
regulated activities; (ii) restrict the types, quantities and concentration of various substances that can be released into the
environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or
prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial
measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned
wells; (v) impose specific safety and health criteria addressing worker protection; and (vi) impose substantial liabilities for
pollution resulting from drilling and completion activities.
The more significant of these existing environmental and occupational health and safety laws and regulations include the
following U.S. laws and regulations, as amended from time to time:
•
•
•
•
•
•
•
•
•
•
the Clean Air Act (“CAA”), which restricts the emission of air pollutants from many sources, imposes various pre-
construction, operational, monitoring, and reporting requirements and has been relied upon by the EPA as authority
for adopting climate change regulatory initiatives relating to greenhouse gas (“GHG”) emissions;
the Federal Water Pollution Control Act, also known as the federal Clean Water Act, which regulates discharges of
pollutants to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction
and rulemaking as protected waters of the United States;
the Comprehensive Environmental Response, Compensation and Liability Act of 1980, which imposes liability on
generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have
occurred or are threatening to occur;
the Resource Conservation and Recovery Act (“RCRA”), which governs the generation, treatment, storage, transport,
and disposal of solid wastes, including hazardous wastes;
the Oil Pollution Act of 1990, which subjects owners and operators of vessels, onshore facilities, and pipelines, as
well as lessees or permittees of areas in which offshore facilities are located, to liability for removal costs and
damages arising from an oil spill in waters of the United States;
the Safe Drinking Water Act (“SDWA”), which ensures the quality of the nation’s public drinking water through
adoption of drinking water standards and controlling the injection of waste fluids into below-ground formations that
may adversely affect drinking water sources;
the Emergency Planning and Community Right-to-Know Act, which requires facilities to implement a safety hazard
communication program and disseminate information to employees, local emergency planning committees, and
response departments on toxic chemical uses and inventories;
the Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and
safety of employees, including the implementation of hazard communications programs designed to inform
employees about hazardous substances in the workplace, potential harmful effects of these substances, and
appropriate control measures;
the Endangered Species Act (“ESA”), which restricts activities that may affect federally identified endangered and
threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or
permanent ban in affected areas; and
the National Environmental Policy Act, which requires federal agencies to evaluate major agency actions having the
potential to impact the environment and that may require the preparation of environmental assessments and more
detailed environmental impact statements that may be made available for public review and comment.
Additionally, there exist regional, state and local jurisdictions in the United States where the Company’s operations are
conducted that also have, or are developing or considering developing, similar environmental and occupational health and
safety laws and regulations governing many of these same types of activities. While the legal requirements imposed in state
and local jurisdictions may be similar in form to federal laws and regulations, in some cases the actual implementation of these
requirements may impose additional, or more stringent, conditions or controls that can significantly restrict, delay or cancel the
permitting, development or expansion of SilverBow's operations or substantially increase the cost of doing business.
Additionally, the Company’s operations may require state-law based permits in addition to federal permits, requiring state
agencies to consider a range of issues, many the same as federal agencies, including, among other things, a project's impact on
wildlife and their habitats, historic and archaeological sites, aesthetics, agricultural operations, and scenic areas. These
operations also are subject to a variety of local environmental and regulatory requirements, including land use, zoning,
building, and transportation requirements. Moreover, whether at the federal, tribal, regional, state and local levels,
16
17
the health and wellbeing of its employees. SilverBow recognizes the importance of providing competitive benefits that support
the wellbeing, medical and financial health of its employees. Annually, the Company surveys its employees on such benefits
along with corporate culture and employee satisfaction, and has taken employee input and market statistics into consideration
as part of its overall compensation package and work environment. For example, in response to employee feedback, the
Company is continuing to offer a flexible and hybrid work-from-home schedule post-pandemic. SilverBow was recognized as
a 2021 top place to work by the Houston Chronicle based on employee survey responses, representing the second year that the
Company achieved this distinction. Overall, the Company is committed to be a workplace of inclusion, with a diversity of
skill, viewpoints, backgrounds, experiences and demographics.
Facilities
At December 31, 2021, SilverBow occupied approximately 16,213 square feet of office space at 920 Memorial City Way,
Suite 850, Houston, Texas. For discussion regarding the term and obligations of this sub-lease refer to Note 6 and Note 8 of
the consolidated financial statements in this Form 10-K.
Available Information
The Company's annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, amendments
to those reports, and changes in stock ownership of its directors and executive officers, together with other documents filed
with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended (the “Exchange Act”),
can be accessed free of charge on SilverBow's website at www.sbow.com as soon as reasonably practicable after the Company
electronically files these reports with the SEC. The SEC maintains an internet site that contains reports, proxy and information
statements, and other information regarding issuers that file electronically with the SEC, which can be accessed at
www.sec.gov. All exhibits and supplemental schedules to SilverBow's reports are available free of charge through the SEC
website.
environmental and occupational health and safety laws and regulations may arise in the future to address potential
environmental concerns such as air emissions, water discharges and disposals or other releases to surface and below-ground
soils and groundwater or to address perceived health or safety-related concerns such as oil and natural gas development in
close proximity to specific occupied structures and/or certain environmentally sensitive or recreational areas. Any such future
developments are expected to have a considerable impact on SilverBow's business and results of operations.
Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative,
civil, and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of
capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of
projects; and the issuance of injunctions restricting, delaying or prohibiting some or all of the Company's activities in a
particular area. Additionally, multiple environmental laws provide for citizen suits, which allow environmental organizations
to act in place of the government and sue operators for alleged violations of environmental law. See Risk Factors under Part I,
Item 1A of this Form 10‑K for further discussion on hydraulic fracturing, ozone standards, induced seismicity, climate change,
and other environmental protection-related subjects. The ultimate financial impact arising from environmental laws and
regulations is neither clearly known nor determinable as existing standards are subject to change and new standards continue
to evolve.
Over time, the trend in environmental regulation is to place more restrictions on activities that may affect the environment
and, thus, any new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or
increased governmental enforcement that result in more stringent and costly pollution control equipment, the occurrence of
restrictions, delays or cancellations in the permitting or performance of projects, or waste handling, storage, transport, disposal
or remediation requirements could have a material adverse effect on SilverBow's financial condition and results of operations.
Moreover, President Biden and the Democratic Party, which now controls Congress, have identified climate change as a
priority, and it is likely that new executive orders, regulatory action, and/or legislation targeting greenhouse gas emissions, or
prohibiting, delaying or restricting oil and gas development activities in certain areas, will be proposed and/or promulgated
during the Biden Administration. In January 2021, President Biden signed an executive order that, among other things,
instructed the Secretary of the Interior to pause new oil and natural gas leases on public lands or in offshore waters pending
completion of a comprehensive review and reconsideration of federal oil and natural gas permitting and leasing practices.
Following that executive order, the acting Secretary of the Interior issued an order imposing a 60-day pause on the issuance of
new leases, permits and right-of-way grants for oil and gas drilling on federal lands, unless approved by senior officials at the
Department of the Interior. In June 2021, a federal judge for the U.S. District Court of the Western District of Louisiana issued
a nationwide preliminary injunction against the pause of oil and natural gas leasing on public lands or in offshore waters while
litigation challenging that aspect of the executive order is ongoing. President Biden’s order also established climate change as
a primary foreign policy and national security consideration, affirms that achieving net-zero greenhouse gas emissions by or
before midcentury is a critical priority, affirms President Biden’s desire to establish the United States as a leader in addressing
climate change, generally further integrates climate change and environmental justice considerations into government
agencies’ decision making, and eliminates fossil fuel subsidies, among other measures.
The Company has incurred and will continue to incur operating and capital expenditures, some of which may be material,
to comply with environmental and occupational health and safety laws and regulations. Historically, SilverBow's
environmental compliance costs have not had a material adverse effect on its results of operations; however, there can be no
assurance that such costs will not be material in the future or that such future compliance will not have a material adverse
effect on its business and operational results.
Employees
As of December 31, 2021, the Company employed 62 people; all were full-time employees. None of SilverBow's
employees were represented by a union and relations with employees are considered to be good.
The Company is committed to its employees and contractors and seeks to support its workforce through its corporate
culture, known as “the SBOWay.” The SBOWay is built on five tenants: One Team, Unleash Potential, Drive Value, Lead the
Way, and Safety Strong. This commitment includes establishing a safe workplace, and SilverBow has implemented health,
safety and environmental management processes into its operations to promote workplace safety. In response to the
COVID-19 pandemic, the Company put in place additional safety measures for the protection of its employees, including extra
cleaning and protective measures along with work-from-home measures for all employees other than essential personnel
whose physical presence was required. Additionally, SilverBow understands that to attract and retain the best talent, it must
provide opportunities for people to grow and develop. Accordingly, the Company provides career development programs,
encompassing the development of technical and management skills, and also offers wellness programs focused on improving
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Item 1A. Risk Factors
Our business and operations are subject to a number of risks and uncertainties as described below; however, the risks and
uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that
we may currently deem immaterial, may become important factors that harm our business, financial condition, results of
operations and cash flow in the future. If any of the following risks actually occur, our business, financial condition, results of
operations and cash flow could suffer and the trading price of our common stock could decline.
Risks in this section are grouped in the following categories: (1) Risks Related to the Business: (2) Macroeconomic and
Financial Risks; (3) Legal and Regulatory Risks; and (4) Risks Related to Ownership of Our Common Stock. Many risks affect
more than one category, and the risks are not in the order of significance or probability of occurrence because they have been
grouped by categories.
Risks Related to the Business:
Oil and natural gas prices are volatile, and a substantial or extended decline in oil and natural gas prices would
adversely affect our financial results, reduce liquidity and impede our growth.
Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future. Prices for oil
and natural gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas,
market uncertainty and a variety of additional factors beyond our control, such as:
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domestic and foreign supplies of oil and natural gas;
price and quantity of foreign imports of oil and natural gas;
actions by the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with
OPEC and other allied producing countries) with respect to oil production levels and announcements of potential
changes in such levels;
level of consumer product demand, including as a result of competition from alternative energy sources;
level of global oil and natural gas exploration and production activity;
domestic and foreign governmental regulations;
stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy
sector or restrict the exploration, development and production of oil and natural gas;
political conditions in or affecting other oil-producing and natural gas-producing countries, including in the Middle
East, South America, Africa and Russia;
weather conditions, natural disasters and global health events, including pandemics;
technological advances affecting oil and natural gas production and consumption;
overall U.S. and global economic and political conditions, including political tensions and war; and
price and availability of alternative fuels.
Our financial condition, revenues, profitability and the carrying value of our properties depend upon the prevailing prices
and demand for oil and natural gas. Any sustained periods of low prices for oil and natural gas are likely to materially and
adversely affect our financial position and reduce our liquidity. This would impact the quantities of oil and natural gas reserves
that we can economically produce, our cash flow available for capital expenditures and continued development of our
operations, making it increasingly difficult to operate our business. Additionally, any extended period of low commodity prices
would impact our ability to access funds through the capital markets, if they are available at all. For example, the COVID-19
pandemic has caused volatility in the market price for crude oil due to the disruption of global supply and demand, and oil and
natural gas prices in the near term may continue to be influenced by the duration and severity of the COVID-19 pandemic,
including any resurgences and the emergence and spread of additional COVID-19 variants, and its resulting impact on oil and
natural gas demand.
The COVID-19 pandemic has adversely affected our business, and the ultimate effect on our business, financial
position, results of operations and financial condition will depend on future developments, which are highly uncertain and
cannot be fully predicted.
In response to the COVID-19 pandemic, governments have tried to slow the spread of the virus by imposing social
distancing guidelines, travel restrictions and stay-at-home orders, which have caused and may continue to cause a significant
decrease in the demand for natural gas and oil. The imbalance between the supply of and demand for these products, as well as
the uncertainty around the extent and timing of an economic recovery, has caused extreme market volatility and a substantial
adverse effect on commodity prices and may continue to cause market volatility and adverse effects on commodity prices.
While our production is more heavily weighted to natural gas, the lack of a market, due to low commodity prices or a future
decrease in commodity prices, or available storage for any one natural gas product or oil could result in us temporarily
curtailing or shutting in such production as we may be unable to curtail the production of individual products in a meaningful
way without reducing the production of other products. Any such shut-in or curtailment, or any inability to obtain favorable
terms for delivery of the natural gas and oil we produce, could adversely affect our financial condition and results of operations.
Any excess supply could also lead to potential curtailments by our purchasers. Additionally, while we believe that any potential
shutting-in of such production will not impact the productivity of such wells when reopened, there is no assurance we will not
have a degradation in well performance upon returning those wells to production. The storing or shutting in of a portion of our
production could potentially also result in increased costs under our midstream and other contracts. Any of the foregoing could
result in an adverse impact on our revenue, financial position and cash flow.
The extent of the impact of the COVID-19 pandemic, including any resurgences and the emergence and spread of
COVID-19 variants, on our business and operational plans is uncertain and depends on various factors, including how the
pandemic and measures taken in response to it impact demand for oil and natural gas, the availability of personnel, equipment
and services critical to our ability to operate our properties and the impact of potential governmental restrictions on travel,
transports and operations. In particular, vaccine mandates that may be announced in jurisdictions in which our business operates
could result in disruptions to our current and potential future workforce and may result in increased attrition, as well as
increased costs in connection with retaining our workforce.
Additionally, the direct and indirect effects of the COVID-19 pandemic or any future outbreak of an infectious disease may
give rise to risks that are currently unknown or have the effect of heightening many of the other risks set forth in these “Item
1A. Risk Factors” in this Annual Report.
Insufficient capital could lead to declines in our cash flow or in our oil and natural gas reserves, or a loss of properties.
The oil and natural gas industry is capital intensive. Our 2022 capital plan, including expenditures for leasehold
acquisitions, drilling and infrastructure and fulfillment of abandonment obligations, is expected to be between $180-$200
million (excluding possible future acquisitions). We had approximately $130.5 million of capital expenditures (excluding
acquisitions) in 2021. Cash flow from operations is a principal source of our financing of our future capital expenditures.
Insufficient cash flow from operations and inability to access capital could lead to the loss of leases that require us to drill new
wells in order to maintain the lease. Lower liquidity and other capital constraints may make it difficult to drill those wells prior
to the lease expiration dates, which could result in our losing reserves and production. Additionally, a decline in cash flow from
operations may require us to revise our capital program or alter or increase our capitalization substantially through the
incurrence of indebtedness or the issuance of debt or equity securities.
Further, developing and exploring properties for oil and natural gas not only requires significant capital expenditures, but
involves a high degree of financial risk, including the risk that no commercially productive oil or natural gas reservoirs will be
encountered. Budgeted costs of drilling, completing, and operating wells are often exceeded and can increase significantly when
drilling costs rise, impacting the Company’s budgeted capital expenditures. Drilling may also be unsuccessful for many
reasons, including title problems, weather, cost overruns, equipment shortages, and mechanical difficulties, which could impact
the Company’s cash flow from operations.
Most of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless
production is established on units containing the acreage.
We own leasehold interests in areas not currently held by production. Unless production in paying quantities is established
or we exercise an extension option on units containing certain of these leases during their terms, the leases will expire. If our
leases expire, we will lose our right to develop the related properties. We have leases on 50,767 net acres in Texas that could
potentially expire during fiscal year 2022, representing approximately 81% of our total net undeveloped acreage in Texas of
62,577 net acres.
Our drilling plans for areas not currently held by production are subject to change based upon various factors. Many of
these factors are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital,
drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation
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constraints and regulatory approvals. On our acreage that we do not operate, we have less control over the timing of drilling;
therefore, there is additional risk of expirations occurring in those sections.
Estimates of proved reserves are uncertain, and revenues from production may vary significantly from expectations.
The quantities and values of our proved reserves included in our year-end 2021 estimates of proved reserves are only
estimates and subject to numerous uncertainties. The accuracy of any reserves estimate is a function of the quality of available
data and of engineering and geological interpretation. These estimates depend on assumptions regarding quantities and
production rates of recoverable oil and natural gas reserves, future prices for oil and natural gas, timing and amounts of
development expenditures and operating expenses, all of which will vary from those assumed in our estimates. If the variances
in these assumptions are significant, many of which are based upon extrinsic events we cannot control, they could significantly
affect these estimates and could result in the actual amounts of oil and natural gas ultimately recovered and future net cash flow
being materially different from the estimates in our reserves reports. These estimates may not accurately predict the present
value of future net cash flow from our oil and natural gas reserves.
Our oil and natural gas exploration and production business involves high risks and we may suffer uninsured losses,
which may be subject to substantial liability claims.
Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business,
financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the
operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
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hurricanes, tropical storms or other natural disasters;
environmental hazards, such as natural gas leaks, oil and produced water spills, pipeline or tank ruptures, encountering
naturally occurring radioactive materials, blowouts, explosions and unauthorized discharges of brine, well stimulation
and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
abnormally pressured formations;
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• mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
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fires and explosions; and
personal injuries and death.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to the Company
due to injury or loss of life, damage to or destruction of wells, production facilities, other property or natural resources, clean-up
responsibilities, regulatory investigations and penalties and suspension of operations. Moreover, a potential result of climate
change is more frequent or more severe weather events or natural disasters. To the extent such weather events or natural
disasters become more frequent or severe, disruptions to our business and costs to repair damaged facilities could increase.
Although the Company currently maintains insurance coverage that it considers reasonable and that is similar to that maintained
by comparable companies in the oil and natural gas industry, it is not fully insured against certain of these risks, such as
business interruption, either because such insurance is not available or because of the high premium costs and deductibles
associated with obtaining and carrying such insurance. Further, we may also elect not to obtain insurance if we believe that the
cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally
are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely
affect our financial condition.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel, water disposal and oilfield services could
adversely affect our ability to execute on a timely basis our exploration and development plans within our budget and
operate profitably.
Shortages or the high cost of drilling rigs, equipment, supplies or personnel, including shortages or unavailability of
personnel, supplies and equipment arising from the COVID-19 pandemic could delay or adversely affect our development and
exploration operations. If the price of oil and natural gas increases, the demand for production equipment and personnel will
likely also increase, potentially resulting in shortages of equipment and personnel. In addition, larger producers may be more
likely to secure access to such equipment by offering drilling companies more lucrative terms. If we are unable to acquire
access to such resources, or can obtain access only at higher prices, this would potentially delay our ability to convert our
reserves into cash flow and could also significantly increase the cost of producing those reserves, thereby negatively impacting
anticipated net income.
We have experienced, and expect to continue to experience, a shortage of labor for certain functions, including due to
concerns around COVID-19, changing oil and natural gas industry investment patterns and other factors, which has increased
our labor costs and negatively impacted our profitability. The extent and duration of the effect of these labor market challenges
are subject to numerous factors, including the continuing effect of the COVID-19 pandemic, vaccine mandates that may be
announced in jurisdictions in which our businesses operate, availability of qualified persons in the markets where we and our
contracted service providers operate and unemployment levels within these markets, capital investment in the oil and natural
gas industry as a whole, behavioral changes, prevailing wage rates and other benefits, inflation, adoption of new or revised
employment and labor laws and regulations (including increased minimum wage requirements) or government programs, safety
levels of our operations, and our reputation within the labor market.
Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are
unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we
use economically and in an environmentally safe manner.
Our operations include the need of water for use in oil and natural gas exploration and production activities. The
Company’s access to water may be limited due to reasons such as prolonged drought, private third party competition for water
in localized areas, or the Company’s inability to acquire or maintain water sourcing permits or other rights. In addition, some
state and local governmental authorities have begun to monitor or restrict the use of water subject to their jurisdiction for
hydraulic fracturing to ensure adequate local water supply. Any such decrease in the availability of water could adversely affect
the Company’s business and financial condition and operations. Moreover, any inability by the Company to locate or
contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact the Company’s exploration
and production operations and have a corresponding adverse effect on the Company’s business and financial condition.
A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.
Our business has become increasingly dependent on digital technologies to conduct day-to-day operations, including
certain of our exploration, development and production activities. We depend on digital technology to estimate quantities of oil
and natural gas reserves, process and record financial and operating data, analyze seismic and drilling information and in many
other activities related to our business. Our technologies, systems and networks may become the target of cyber attacks or
information security breaches that could result in the disruption of our business operations, damage to our properties and/or
injuries. For example, unauthorized access to our seismic data, reserves information or other proprietary information could lead
to data corruption, communication interruption, or other operational disruptions in our drilling or production operations.
Additionally, a cyber attack or information security breach could expose our employees, customers and suppliers to risks of
misuse of confidential personal information, which may expose us to reputational damage or legal liability.
We have experienced, and expect to continue to confront, unsuccessful efforts by hackers and other third parties to gain
unauthorized access or deny access to, or otherwise disrupt, our information technology systems and networks. To date we are
not aware of any material losses relating to cyber attacks or any material impact on our operations to date, however there can be
no assurance that we will not suffer such losses in the future and future incidents could have a material adverse effect on our
business, financial condition, results of operations or liquidity. As cyber threats continue to evolve, we may be required to
expend significant additional resources to continue to modify or enhance our protective measures or to investigate and
remediate any cyber vulnerabilities.
In addition to the risks presented to our systems and networks, cyber attacks affecting oil and natural gas distribution
systems maintained by third parties, or the networks and infrastructure on which they rely, could delay or prevent delivery of
our production to markets. A cyber attack of this nature would be outside our control, but could have a material, adverse effect
on our business, financial condition and results of operations.
Our lack of diversification increases the risk of an investment in us and we are vulnerable to risks associated with
operating primarily in one major contiguous area.
All of our operations are in the Eagle Ford Shale and Austin Chalk in South Texas, providing for efficiencies and
opportunities as a single-basin operator, but making us vulnerable to risks associated with operating in one geographic area.
While the Company continually works to balance its oil and gas commodity mix through product optimization, development
timing, acquisitions and lease purchases, a number of our properties could experience any of the same conditions at the same
time, resulting in a relatively greater impact on our results of operations than they might have on other companies that are more
diversified. In particular, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or
interruptions of production from wells in which we have an interest that are caused by transportation capacity constraints,
curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation,
natural disasters, adverse weather conditions, water shortages or other drought related conditions, plant closures for scheduled
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maintenance or interruption of transportation of crude oil or natural gas produced from wells in the Eagle Ford and Austin
Chalk. Such delays or interruptions could have a material adverse effect on our financial condition, results of operations and
cash flow.
Our property acquisitions carry significant risks.
Acquisition of oil and gas properties is a key element of maintaining and growing reserves and production. Competition for
these assets has been and will continue to be intense. We may not be able to identify attractive acquisition opportunities. Even if
we do identify attractive candidates, we may not be able to complete the acquisition or do so on commercially acceptable terms.
In the event we do complete an acquisition, such as the recently completed acquisition of certain oil and gas assets from Teal
Natural Resources, LLC and Castlerock Production, LLC, its success will depend on a number of factors, many of which are
beyond our control. These factors include future crude oil, NGL and natural gas prices, the ability to reasonably estimate or
assess the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves, future
operating and capital costs, results of future exploration, exploitation and development activities on the acquired properties and
future abandonment, possible future environmental or other liabilities and the effect on our liquidity or financial leverage of
using available cash or debt to finance acquisitions. There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves, actual future production rates and associated costs and the assumption of potential liabilities with
respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. A
customary review of subject properties will not necessarily reveal all existing or potential problems.
Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of
the acquired properties if they have substantially different operating and geological characteristics or are in different geographic
locations than our existing properties. To the extent that acquired properties are substantially different than our existing
properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited.
Integrating acquired businesses and properties involves a number of special risks. These risks include the possibility that
management may be distracted from regular business concerns by the need to integrate operations and systems, that unforeseen
difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other
similar risks could lead to potential adverse short-term or long-term effects on our operating results, and may cause us to not be
able to realize any or all of the anticipated benefits of the acquisitions.
Macroeconomic and Financial Risks:
from their current level or remain volatile for an extended period of time, our ability to comply with these covenants may be
impaired. A failure to comply with the covenants, ratios or tests in our Debt Facilities or any future indebtedness could result in
an event of default under our Debt Facilities or our future indebtedness, which, if not cured or waived, could have a material
adverse effect on our business, financial condition and results of operations.
If an event of default under either of our Debt Facilities occurs and remains uncured, the lenders or holders under the
applicable Credit Facility:
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would not be required to lend any additional amounts to us;
could elect to declare all borrowings or notes outstanding, together with accrued and unpaid interest and fees, to be due
and payable;
• may have the ability to require us to apply all of our available cash to repay these borrowings or notes; or
• may prevent us from making debt service payments under our other agreements.
The borrowing base under our Credit Facility is redetermined at least semi-annually, based in part on assumptions of the
administrative agent with respect to, among other things, crude oil and natural gas prices. In November 2021, our borrowing
base was increased from $300 million to $460 million as part of our regularly scheduled redetermination. In contrast, a negative
adjustment to the borrowing base could occur if crude oil and natural gas prices used by the lenders are significantly lower than
those used in the last redetermination, including as result of a decline in commodity prices or an expectation that reduced prices
will continue. The next redetermination of our borrowing base in scheduled to occur in spring of 2022. As of February 26,
2022, we had $233 million outstanding under our Credit Facility. In the event that the amount outstanding under our Credit
Facility exceeds the redetermined borrowing base, we could be forced to repay a portion of our borrowings. In addition, the
portion of our borrowing base made available to us for borrowing is subject to the terms and covenants of our Credit Facility,
including compliance with the ratios and other financial covenants of such facility.
Our obligations under the Debt Facilities are collateralized by first and second priority liens and security interests on
substantially all of our assets, including mortgage liens on oil and natural gas properties having at least 90% of the PV-9
(determined using commodity price assumptions by the administrative agent of the Credit Facility) of the borrowing base
properties (with respect to the Credit Facility) or the oil and gas properties constituting proved reserves as set forth in the most
recent reserve report (with respect to the Second Lien). If we are unable to repay our indebtedness under the Debt Facilities,
(including any amount of borrowings in excess of the borrowing base resulting from a redetermination of our Credit Facility),
the lenders could seek to foreclose on substantially all our assets.
Our Debt Facilities, as defined below, contain operating and financial restrictions that may restrict our business and
We have written down the carrying values on our oil and natural gas properties in the past and could incur additional
financing activities.
write-downs in the future.
Our Credit Facility and Second Lien (collectively “Debt Facilities”) contain a number of restrictive covenants that impose
significant operating and financial restrictions on us, including restrictions on our ability to, among other things:
sell assets, including equity interests in our subsidiary;
redeem our debt;
incur or guarantee additional indebtedness;
create or incur certain liens;
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• make investments;
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redeem or prepay other debt;
enter into agreements that restrict distributions or other payments from our restricted subsidiary to us;
consolidate, divide, merge or transfer all or substantially all of our assets;
engage in transactions with affiliates;
create unrestricted subsidiaries;
enter into swap agreements beyond certain maximum thresholds;
enter into sale and leaseback transactions; and
engage in certain business activities.
The SEC accounting rules require that on a quarterly basis we review the carrying value of our oil and natural gas
properties for possible write-down or impairment (the "ceiling test"). Any capital costs in excess of the ceiling amount must be
permanently written down. If oil and natural gas prices remain low for an extended period of time, we could be required to
record additional non-cash write-downs of our oil and gas properties. For example, due to the effects of pricing and timing of
projects we reported a non-cash impairment write-down, on a pre-tax basis, of $355.9 million for the year ended December 31,
2020. While the demand for and price of oil and natural gas has generally recovered from the lows experienced in 2020, if
future capital expenditures outpace future discounted net cash flow in our reserve calculations, if we have significant declines in
our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flow from proved oil
and natural gas reserves) or if oil or natural gas prices decline, it is possible that non-cash write-downs of our oil and natural gas
properties will occur again in the future. We cannot control and cannot predict what future prices for oil and natural gas will be;
therefore, we cannot estimate the amount of any potential future non-cash write-down of our oil and natural gas properties due
to decreases in oil or natural gas prices. However, it is reasonably possible that we will record additional ceiling test write-
downs in future periods. Refer to Note 1 of the consolidated financial statements in this Form 10-K for further discussion of the
ceiling test calculation.
A worldwide financial downturn or negative credit market conditions may impact our counterparties and have lasting
effects on our liquidity, business and financial condition that we cannot control or predict.
As a result of these covenants, we are limited in the manner in which we conduct our business, and we may be unable to
engage in favorable business activities or finance future operations or capital needs.
Our ability to comply with some of the covenants and restrictions contained in our Debt Facilities may be affected by
events beyond our control. If market or other economic conditions deteriorate or if oil and natural gas prices decline further
Global economic conditions, such as those attributable to the COVID-19 pandemic, may adversely affect the financial
viability of and increase the credit risk associated with our purchasers, suppliers, insurers, and commodity derivative
counterparties to perform under the terms of contracts or financial arrangements we have with them. Although we have
heightened our level of scrutiny of our contractual counterparties and take reasonable steps to transact with financially solvent
banks, creditors and counterparties, our assessment of the risk of non-performance by various parties is subject to sudden
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swings in the financial and credit markets. This same crisis may adversely impact insurers and their ability to pay current and
future insurance claims that we may have.
Our future access to capital could be limited due to tightening credit markets, particularly with respect to the oil and gas
industry, that could affect our ability to fund our future capital projects. In addition, long-term restriction upon or freezing of
the capital markets and legislation related to financial and banking reform may affect short-term or long-term liquidity.
Our hedging program may limit potential gains from increases in commodity prices, result in losses, or be inadequate to
protect us against continuing and prolonged declines in commodity prices.
We enter into arrangements to hedge a portion of our production from time to time to reduce our exposure to fluctuations in
oil, natural gas and natural gas liquids prices and to achieve more predictable cash flow. Our hedges at December 31, 2021 were
in the form of collars, swaps, put and call options, basis swaps, and other structures placed with the commodity trading
branches of certain national banking institutions and with certain other commodity trading groups. These hedging arrangements
may limit the benefit we could receive from increases in the market or spot prices for oil, natural gas and natural gas liquids.
We cannot be certain that the hedging transactions we have entered into, or will enter into, will adequately protect us from
continuing volatility or prolonged declines in oil and natural gas prices. To the extent that oil and natural gas prices remain
volatile or decline further, we would not be able to hedge future production at the same pricing level as our current hedges and
our results of operations and financial condition may be negatively impacted.
In addition, our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative
contract, particularly during periods of falling commodity prices. Disruptions in the financial markets or other factors outside
our control could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the
terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to
perform, and even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending on
market conditions at the time. If the creditworthiness of any of our counterparties deteriorates and results in their
nonperformance, we could incur a significant loss.
Legal and Regulatory Risks:
Pollution and property contamination arising from the Company’s operations and the nearby operations of other oil
and natural gas operators could expose the Company to significant costs and liabilities.
The performance of the Company’s operations may result in significant environmental costs and liabilities as a result of
handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater or other fluid discharges related to
operations, and due to historical industry operations and waste disposal practices. Spills or other unauthorized releases of
regulated substances by or resulting from the Company’s operations, or the nearby operations of other oil and natural gas
operators, could expose the Company to material losses, expenditures and liabilities under environmental laws and regulations.
Certain of the properties upon which the Company conducts operations were acquired from third parties, whose actions with
respect to the management and disposal or release of hydrocarbons, hazardous substances or wastes at or from such properties
were not under the Company’s control. Moreover, certain of these laws may impose strict liability, which means that in some
situations the Company could be exposed to liability as a result of the Company’s conduct that was lawful at the time it
occurred or the conduct of, or conditions caused by, prior operators or other third parties. Neighboring landowners and other
third parties may file claims against the Company for personal injury or property damage allegedly caused by the release of
pollutants into the environment. New laws and regulations, amendment of existing laws and regulations, reinterpretation of
legal requirements or increased governmental enforcement relating to environmental requirements may occur, resulting in the
occurrence of restrictions, delays or cancellations in the permitting or performance of new or expanded projects, or more
stringent or costly well drilling, construction, completion or water management activities or waste handling, storage, transport,
disposal or cleanup requirements. Any of these developments could require the Company to make significant expenditures to
attain and maintain compliance and may otherwise have a material adverse effect on the oil and natural gas exploration and
production industry in general in addition to the Company’s own results of operations, competitive position or financial
condition. The Company may not be able to recover some or any of its costs with respect to such developments from insurance.
Government regulation of the Company’s activities could adversely affect the Company and its operations.
The oil and natural gas business is subject to extensive governmental regulation under which, among other things, rates of
production from oil and natural gas wells may be regulated. Governmental regulation also may affect the market for the
Company’s production and operations. Costs of compliance with governmental regulation are significant, and the cost of
compliance with new and emerging laws and regulations and the incurrence of associated liabilities could adversely affect the
results of the Company. Numerous executive, legislative and regulatory proposals affecting the oil and natural gas industry
have been introduced, are anticipated to be introduced, or are otherwise under consideration, by the President, Congress, state
legislatures and various federal and state agencies. We cannot predict the timing or impact of new or changed laws, regulations,
or permit requirements or changes in the ways that such laws, regulations, or permit requirements are enforced, interpreted or
administered. For example, various governmental agencies, including the EPA and analogous state agencies, the federal Bureau
of Land Management (“BLM”), and the Federal Energy Regulatory Commission can enact or change, begin to enforce
compliance with, or otherwise modify their enforcement, interpretation or administration of, certain regulations that could
adversely affect the Company. Additionally, the current presidential administration may increase the likelihood of potential
changes in these laws and regulations and the enforcement of any existing legislation or directives by government authorities.
The trend toward stricter standards, increased oversight and regulation and more extensive permit requirements, along with any
future laws and regulations, could result in increased costs or additional operating restrictions which could have an effect on the
Company, its operations, the demand for oil and natural gas, or the prices at which it can be sold. However, until such
legislation or regulations are enacted into law or adopted and thereafter implemented, it is not possible to gauge their impact on
our future operations or our results of operations and financial condition.
The Company’s operations are subject to environmental and worker safety and health laws and regulations that may
expose the Company to significant costs and liabilities and could delay the pace or restrict the scope of the Company’s
operations.
The Company’s oil and natural gas exploration, production and development operations are subject to stringent federal,
state and local laws and regulations governing worker safety and health, the release or disposal of materials into the
environment or otherwise relating to environmental protection. Numerous governmental entities, including the EPA, OSHA and
analogous state agencies, have the power to enforce compliance with these laws and regulations, which may require the
Company to take actions resulting in costly capital and operating expenditures at its wells and properties. These laws and
regulations may restrict or affect the Company’s business in many ways, including applying specific health and safety criteria
addressing worker protection, requiring the acquisition of a permit before drilling or other regulated activities commence,
restricting the types, quantities and concentration of substances that can be released into the environment, limiting or
prohibiting construction or drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and
imposing substantial liabilities for pollution resulting from the Company’s operations. Failure to comply with these laws and
regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of
investigative, remedial or corrective action obligations, the occurrence of restrictions, delays or cancellations in the permitting,
development or expansion of projects, and the issuance of orders enjoining performance of some or all of the Company’s
operations in a particular area. We could be exposed to liabilities for cleanup costs, natural resource damages, and other
damages under these laws and regulations, with certain of these legal requirements imposing strict liability for such damages
and costs, even though the conduct in pursuing the Company’s operations was lawful at the time it occurred or the conduct
resulting in such damage and costs were caused by prior operators or other third-parties
Over time, environmental laws and regulations in the United States protecting the environment generally have become
more stringent and are expected to continue to do so in the future. If existing environmental regulatory requirements or
enforcement policies change or new regulatory or enforcement initiatives are developed and implemented in the future, the
Company may be required to make significant, unanticipated capital and operating expenditures with respect to its continued
operations. Moreover, these risks are likely to be enhanced with the current presidential administration and Democrats
controlling Congress. Examples of recent environmental regulations include the following:
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Ground-Level Ozone Standards. In 2015, the EPA issued a final rule under the CAA, lowering the National Ambient
Air Quality Standard (“NAAQS”) for ground-level ozone from 75 parts per billion to 70 parts per billion under both
the primary and secondary standards to provide requisite protection of public health and welfare, respectively. Since
that time, the EPA has issued area designations with respect to ground-level ozone and final requirements that apply to
state, local, and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. State implementation of
the revised NAAQS could, among other things, require installation of new emission controls on some of the
Company’s equipment, result in longer permitting timelines, and significantly increase the Company's capital
expenditures and operating costs arising from the program’s operations.
EPA Review of Drilling Waste Classification. Drilling, fluids, produced water and most of the other wastes associated
with the exploration, development and production of oil or natural gas, if properly handled, are currently exempt from
regulation as hazardous waste under the RCRA and instead, are regulated under RCRA’s less stringent non-hazardous
waste provisions. However, it is possible that certain oil and natural gas drilling and production wastes now classified
as non-hazardous could be classified as hazardous wastes in the future. Any future loss of the RCRA exclusion for
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drilling fluids, produced waters and related wastes could result in an increase in the Company’s costs to manage and
dispose of generated wastes, which could have a material adverse effect on the industry as well as on the Company’s
business.
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Federal Jurisdiction over Waters of the United States. In 2015, the EPA and U.S. Army Corps of Engineers (“Corps”)
under the Obama Administration released a final rule outlining federal jurisdictional reach under the Clean Water Act,
over waters of the United States, including wetlands. However, the EPA rescinded this rule in 2019 and promulgated
the Navigable Waters Protection Rule in 2020. The Navigable Waters Protection Rule defined what waters qualify as
navigable waters of the United States and are under Clean Water Act jurisdiction. This new rule has generally been
viewed as narrowing the scope of waters of the United States as compared to the 2015 rule, but litigation in multiple
federal district courts is currently challenging the rescission of the 2015 rule and the promulgation of the Navigable
Waters Protection Rule. In June 2021, the Biden Administration announced plans to develop its own definition for
jurisdictional waters, and in August 2021, a federal judge for the U.S. District Court for the District of Arizona issued
an order striking down the Navigable Water Protection Rule. On December 7, 2021, the U.S. Environmental
Protection Agency and the Department of the Army announced a proposed rule to revise the definition of “waters of
the United States,” which would return to the 2015 definition of “waters of the United States,” updated to reflect
consideration of Supreme Court decisions. On January 24, 2022, the Supreme Court agreed to consider the scope of
the Clean Water Act again in Sackett v. EPA. To the extent that a revised rule or Supreme Court decision expands the
scope of the Clean Water Act’s jurisdiction in areas where the Company conducts operations, the Company could
incur increased costs and restrictions, delays or cancellations in permitting or projects, which developments could
expose it to significant costs and liabilities.
Additionally, the federal Occupational Safety and Health Act and analogous state occupational safety and health laws
require the program manager to organize information about materials, some of which may be hazardous or toxic, that are used,
released or produced in the Company’s operations. Moreover, the OSHA hazard communication standard, the EPA community
right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state
statutes require that information be maintained concerning hazardous materials used or produced in the Company’s operations
and that this information be provided to employees, state and local government authorities and citizens.
Compliance of the Company with these regulations or other laws, regulations and regulatory initiatives, or any other new
environmental and occupational health and safety legal requirements could, among other things, require the Company to install
new or modified emission controls on equipment or processes, incur longer permitting timelines, and incur significantly
increased capital or operating expenditures, which costs may be significant. Moreover, any failure of the Company’s operations
to comply with applicable environmental laws and regulations may result in governmental authorities taking actions against the
Company that could adversely impact its operations and financial condition.
The ESA and other restrictions intended to protect certain species of wildlife govern our oil and natural gas operations,
which constraints could have an adverse impact on our ability to expand some of our existing operations or limit our ability
to explore for and develop new oil and natural gas wells.
The ESA and comparable state laws and other regulatory initiatives restrict activities that may affect endangered or
threatened species or their habitats. Similar protections are offered to migrating birds under the federal Migratory Bird Treaty
Act and the Bald and Golden Eagle Protection Act. Some of the Company’s operations may be located in or near areas that are
designated as habitat for endangered or threatened species and, in these areas, the Company may be obligated to develop and
implement plans to avoid potential adverse effects to protected species and their habitats, and the Company may be prohibited
from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when its
operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete
halt to the Company’s drilling activities in certain locations if it is determined that such activities may have a serious adverse
effect on a protected species. Moreover, the U.S. Fish and Wildlife Service, may make determinations on the listing of species
as endangered or threatened under the ESA pursuant to specific timelines. The identification or designation of previously
unprotected species as threatened or endangered or the redesignation of lesser protected species in areas where underlying
property operations are conducted could cause the Company to incur increased costs arising from species protection measures,
time delays or limitations or cancellations on its exploration and production activities, which costs, delays, limitations or
cancellations could have an adverse impact on the Company’s ability to develop and produce reserves. If the Company were to
have a portion of its leases designated as critical or suitable habitat, it could adversely impact the value of its leases.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased
costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect the
Company’s production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of gas and/or oil from dense
subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand or other proppant and
chemical additives under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate
production. The Company uses hydraulic fracturing techniques in certain of its operations. Hydraulic fracturing typically is
regulated by state oil and gas commissions or similar state agencies, but several federal agencies have conducted studies or
asserted regulatory authority over certain aspects of the process. For example, in late 2016, the EPA released its final report on
the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated
with hydraulic fracturing may impact drinking water resources under some circumstances. Additionally, the EPA has asserted
regulatory authority pursuant to the SDWA Underground Injection Control (“UIC”) program over hydraulic fracturing activities
involving the use of diesel and issued guidance covering such activities as well as published an Advance Notice of Proposed
Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic
fracturing. The EPA also issued final regulations in 2012 and in 2016 under the CAA that govern performance standards,
including standards for the capture of methane and volatile organic compound (“VOC”) air emissions released during oil and
natural gas hydraulic fracturing. However, in August 2020, the EPA rescinded methane and volatile organic compound
emissions standards for new and modified oil and gas transmission and storage infrastructure, as well as methane limits for new
and modified oil and gas production and processing equipment. The EPA also relaxed requirements for oil and gas operators to
monitor emissions leaks. Moreover, the EPA has published an effluent limit guideline final rule prohibiting the discharge of
wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants.
Also, the BLM published a final rule in 2015 that established new or more stringent standards relating to hydraulic fracturing
on federal and American Indian lands but the BLM rescinded the 2015 rule in late 2017; however, litigation challenging the
BLM’s decision to rescind the 2015 rule remains pending in the U.S. Court of Appeals for the Ninth Circuit.
From time to time, legislation has been considered, but not adopted, in the U.S. Congress to provide for federal regulation
of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Moreover, these risks
are likely to be enhanced with the current presidential administration and Democrats controlling Congress. Additionally, a bill
was introduced in the Senate on January 28, 2020 that, if enacted as proposed, would ban hydraulic fracturing nationwide by
2025.
In addition, certain states, including Texas where we conduct operations, have adopted, and other states are considering
adopting legal requirements that could impose new or more stringent permitting, public disclosure, or well construction
requirements on hydraulic fracturing activities. States could elect to place certain prohibitions on hydraulic fracturing, following
the approach taken by the States of Maryland, New York and Vermont. Local governments also may seek to adopt ordinances
within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities
in particular. If new or more stringent federal, state, or local laws, regulations, presidential executive orders or other legal
restrictions relating to the hydraulic fracturing process are adopted in areas where the Company operates, the Company could
incur potentially significant added costs to comply with such requirements, experience restrictions, delays or cancellation in the
pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and
litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or
regulation could also lead to added restrictions, delays or cancellations with respect to our operations or increased operating
costs in our production of oil and natural gas. The adoption of any federal, state or local laws or the implementation of
regulations restricting or banning some or all of hydraulic fracturing could result in delays, eliminate certain drilling and
injection activities and prohibit or make more difficult or costly the performance of hydraulic fracturing. These developments
could adversely affect demand for our production and have a material adverse effect on our business or results of operations.
Federal or state legislative and regulatory initiatives related to induced seismicity could result in operating restrictions
or delays that could adversely affect the Company’s production of oil and natural gas.
Operations associated with our production and development activities generate drilling muds, produced waters and other
waste streams, some of which may be disposed of by means of injection into underground wells situated in non-producing
subsurface formations. These disposal wells are regulated pursuant to the UIC program established under the SDWA and
analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for construction and
operation of such disposal wells, establishes minimum standards for disposal well operations, and restricts the types and
quantities of fluids that may be disposed. While these permits are issued pursuant to existing laws and regulations, these legal
requirements are subject to change based on concerns of the public or governmental authorities regarding such disposal
activities. One such concern relates to seismic events near underground disposal wells used for the disposal by injection of
produced water or certain other oilfield fluids resulting from oil and natural gas activities. Developing research suggests that the
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link between seismic activity and produced water disposal may vary by region, and that only a very small fraction of the tens of
thousands of injection wells have been suspected to be, or may have been, the likely cause of induced seismicity. In 2016, the
United States Geological Survey identified Texas, where the Company conducts operations, as one of six states with more
significant rates of induced seismicity. Since that time, the United States Geological Survey indicates that this rate has
decreased in Texas, although concern continues to exist over earthquakes arising from induced seismic activities.
In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing,
additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between
seismicity and the use of such wells. For example, Oklahoma has issued rules for produced water disposal wells that imposed
certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from
time to time, is developing and implementing plans directing certain wells where seismic incidents have occurred to restrict or
suspend disposal well operations. In Texas, the Railroad Commission of Texas has adopted similar rules for the permitting of
produced water disposal wells. Another consequence of seismic events may be lawsuits alleging that disposal well operations
have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These
developments could result in additional regulation and restrictions on the use of injection wells in connection with Company
activities to dispose of produced water and certain other oilfield fluids. Increased regulation and attention given to induced
seismicity also could lead to greater opposition, including litigation, to oil and natural gas activities utilizing injection wells for
waste disposal. Any one or more of these developments may result in the Company having to limit disposal well volumes,
disposal rates or locations, or require third party disposal well operators the Company may engage to dispose of produced water
generated by Company activities to shut down disposal wells, which development could adversely affect the Company’s
production or result in the Company incurring increased costs and delays with respect to Company operations.
The Company’s operations are subject to a number of risks arising out of the threat of climate change that could result
in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduced demand for the
oil and natural gas the Company produces
Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous
proposals have been made and are likely to continue to be made at the international, national, regional and state levels of
government to monitor and limit emissions of GHGs as well as to restrict or eliminate such future emissions. As a result, our
operations as well as the operations of our oil and natural gas exploration and production customers are subject to a series of
regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of
GHGs.
At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has
determined that emissions of GHGs present an endangerment to public health and the environment and has adopted regulations
under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration construction
and Title V operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and
annual reporting of GHG emissions from certain petroleum and natural gas system sources, implement CAA emission standards
directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and
together with the U.S. Department of Transportation, implement GHG emissions limits on vehicles manufactured for operation
in the United States. Additionally, various states and groups of states have adopted or are considering adopting legislation,
regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes,
reporting and tracking programs, and restriction of emissions. At the international level, there exists the United Nations-
sponsored “Paris Agreement,” which is a non-binding agreement for nations to limit their GHG emissions through individually-
determined reduction goals every five years after 2020. Although the Trump Administration had withdrawn the United States
from the Paris Agreement in November 2020, the Biden Administration officially reentered the United States into the
agreement in February 2021 and committed the United States to reducing its greenhouse gas emissions by 50 to 52% from 2005
levels by 2030. In November 2021, the United States and other countries entered into the Glasgow Climate Pact, which includes
a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies,
reducing methane emissions 30% by 2030, and cooperating toward the advancement of the development of clean energy.
President Biden and the Democratic Party, which now controls Congress, have identified climate change as a priority, and
it is likely that new executive orders, regulatory action, and/or legislation targeting greenhouse gas emissions, or prohibiting,
delaying or restricting oil and gas development activities in certain areas, will be proposed and/or promulgated during the Biden
Administration. In January 2021, President Biden signed an executive order that, among other things, instructed the Secretary
of the Interior to pause new oil and natural gas leases on public lands or in offshore waters pending completion of a
comprehensive review and reconsideration of federal oil and natural gas permitting and leasing practices. Following that
executive order, the acting Secretary of the Interior issued an order imposing a 60-day pause on the issuance of new leases,
permits and right-of-way grants for oil and gas drilling on federal lands, unless approved by senior officials at the Department
of the Interior. In June 2021, a federal judge for the U.S. District Court of the Western District of Louisiana issued a nationwide
preliminary injunction against the pause of oil and natural gas leasing on public lands or in offshore waters while litigation
challenging that aspect of the executive order is ongoing.
President Biden’s executive order also established climate change as a primary foreign policy and national security
consideration, affirms that achieving net-zero greenhouse gas emissions by or before midcentury is a critical priority, affirms
the Biden Administration’s desire to establish the United States as a leader in addressing climate change, generally further
integrates climate change and environmental justice considerations into government agencies’ decision-making, and eliminates
fossil fuel subsidies, among other measures. Litigation risks are also increasing, as a number of cities, local governments, and
other plaintiffs have sought to bring suit against the largest oil and natural gas exploration and production companies in state or
federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to
global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a
result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded
their investors by failing to adequately disclose those impacts.
There are also increasing financial risks for fossil fuel producers, as stockholders and bondholders currently invested in
fossil fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all
of their investments into non-fossil fuel energy related investments. Institutional investors who provide capital to fossil fuel
energy companies also have become more attentive to sustainability issues, and some of them may elect not to provide funding
for fossil fuel energy companies. Additionally, the lending and investment practices of institutional lenders have been the
subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the
international Paris Agreement, and foreign citizenry concerned about climate change not to provide funding for fossil fuel
producers. Limitation of investments in and financings for fossil fuel energy could restrict the availability of capital, resulting in
the restriction, delay, or cancellation of development and production activities.
The adoption and implementation of any international, federal or state laws or regulations that impose more stringent
standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce
oil and natural gas or generate GHG emissions could require the Company to incur increased operating costs or costs of
compliance and thereby reduce demand for the oil and natural gas produced by the Company. Additionally, political, litigation,
and financial risks may result in the Company restricting or cancelling development or production activities, incurring liability
for infrastructure damages as a result of climate changes, or impairing its ability to continue to operate in an economic manner,
which also could reduce demand for or lower the value of, the oil and natural gas the Company produces. One or more of these
developments could have a material adverse effect on the Company’s business, financial condition and results of operations.
Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes
that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If
any such effects were to occur, they could have an adverse effect on the Company’s operations. At this time, the Company has
not developed a comprehensive plan to address the legal, economic, social, or physical impacts of climate change on the
Company’s operations.
Changes to the U.S. federal tax laws could adversely affect our financial position, results of operations and cash flow.
Our future effective tax rates could be adversely affected by changes in tax laws, both domestically and internationally, or
the interpretation or application thereof. From time to time, U.S. and foreign tax authorities, including state and local
governments consider legislation that could increase our effective tax rate. For example, the U.S. Congress has advanced a
variety of tax legislation proposals, and while the final form of any legislation is uncertain, the current proposals, if enacted,
could have a material effect on our effective tax rate. Additionally, in recent years, lawmakers and the U.S. Department of the
Treasury have proposed certain significant changes to U.S. tax laws applicable to oil and gas companies. These changes
include, but are not limited to; (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination
of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain
geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be
proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would
be. This legislation or any future similar changes in U.S. federal income tax laws, as well as any similar changes in state law,
could eliminate or postpone certain tax deductions that currently are available with respect to natural gas and oil exploration and
production, which could negatively affect our results of operations and financial condition.
We may not be able to utilize a portion of our net operating loss carryforwards (“NOLs”) to offset future taxable income
for U.S. federal income tax purposes, which could adversely affect our net income and cash flow.
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As of December 31, 2021, we had federal net operating loss (“NOL”) carryforwards of approximately $463 million,
approximately $274 million of which will expire in varying amounts beginning in 2033 through 2037. Utilization of these
NOLs depends on many factors, including our future taxable income, which cannot be assured. In addition, Section 382 of the
Internal Revenue Code of 1986, as amended (the “Code”), generally imposes an annual limitation on the amount of an NOL
that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under
Section 382 of the Code). An ownership change generally occurs if one or more shareholders (or groups of shareholders) who
are each deemed to own at least 5 percent of the corporation’s stock increase their ownership by more than 50 percentage points
over their lowest ownership percentage within a rolling three-year period. In the event that an ownership change occurs with
respect to a corporation following its recognition of an NOL, utilization of such NOL is subject to an annual limitation,
generally determined by multiplying the value of the corporation’s stock at the time of the ownership change by the applicable
long-term tax-exempt rate. However, this annual limitation would be increased under certain circumstances by recognized built-
in gains of the corporation existing at the time of the ownership change. In the case of an NOL that arose in a taxable year
beginning before January 1, 2018, any unused annual limitation with respect to an NOL generally may be carried over to later
years, subject to the expiration of such NOL 20 years after it arose. Future changes in our stock ownership or future regulatory
changes could also limit our ability to utilize our NOLs. To the extent we are not able to offset future taxable income with our
NOLs, our net income and cash flow may be adversely affected.
Legal proceedings could result in liability affecting our results of operations.
We are involved in various legal proceedings, such as title, royalty, environmental or contractual disputes, in the ordinary
course of business. We defend ourselves vigorously in all such matters, if appropriate.
Because we maintain a portfolio of assets in the various areas in which we operate, the complexity and types of legal
proceedings with which we may become involved may vary, and we could incur significant legal and support expenses in
different jurisdictions. If we are not able to successfully defend ourselves, there could be a delay or even halt in our exploration,
development or production activities or other business plans, resulting in a reduction in reserves, loss of production and reduced
cash flow. Legal proceedings could result in a substantial liability. In addition, legal proceedings distract management and other
personnel from their primary responsibilities.
Risks Related to Ownership of Our Common Stock:
For as long as we are a smaller reporting company, we will not be required to comply with certain disclosure
requirements that apply to other public companies.
We are currently a “smaller reporting company” as defined by Rule 12b-2 of the Exchange Act. “Smaller reporting
companies” are able to provide simplified executive compensation disclosures in their filings, and have certain other scaled
disclosure obligations in their SEC filings, including, among other things, being required to provide only two years of audited
financial statements in annual reports. The scaled disclosures we provide in our SEC filings due to our status as a “smaller
reporting company” may make it harder for investors to analyze our results of operations and financial prospects. If some
investors find our common stock to be less attractive as a result of the scaled disclosures, there also may be a less active trading
market for our common stock and our trading price may be more volatile.
There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests
of our other stockholders.
Funds associated with Strategic Value Partners LLC (“SVP”) own approximately 27%, of our outstanding common stock.
SVP currently has a right to nominate two of our directors under our director nominating agreement described below. Other
former noteholders who received our common stock pursuant to our plan of reorganization, collectively hold the current right to
nominate one additional director. Our current board is limited to seven directors under the terms of the director nomination
agreement. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions,
divestitures or other transactions, including the issuance of additional shares or debt, that, in their judgment, could enhance their
investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our
common stock. Furthermore, we have entered into a director nomination agreement with SVP and other former holders of our
senior notes that provides for certain continuing nomination rights subject to conditions on share ownership. In addition, our
significant concentration of share ownership may adversely affect the trading price of our common shares because investors
may perceive disadvantages in owning shares in companies with significant stockholders. For example, this concentration of
ownership may limit our other stockholders’ ability to influence corporate matters, as our significant stockholders are able to
influence matters that require approval by our stockholders, including the election and removal of directors, changes to our
organizational documents and approval of acquisition offers and other significant corporate transactions.
Certain provisions of our Charter and our Bylaws may make it difficult for stockholders to change the composition of
our Board and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.
Certain provisions of our Charter and our Bylaws and our existing director nomination agreement may have the effect of
delaying or preventing changes in control if our Board determines that such changes in control are not in the best interests of the
Company and our stockholders. The provisions in our Charter and Bylaws and our existing director nomination agreement
include, among other things, those that:
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provide for a classified board of directors;
authorize our Board to issue preferred stock and to determine the price and other terms, including preferences and
voting rights, of those shares without stockholder approval;
establish advance notice procedures for nominating directors or presenting matters at stockholder meetings;
provide SVP and certain other institutional stockholders the right to nominate up to three of our directors; and
limit the persons who may call special meetings of stockholders;
While these provisions have the effect of encouraging persons seeking to acquire control of the Company to negotiate with
our Board, they could enable the Board to hinder or frustrate a transaction that some, or a majority, of the stockholders may
believe to be in their best interests and, in that case, may prevent or discourage attempts to remove and replace incumbent
directors. These provisions may frustrate or prevent any attempts by our stockholders to replace or remove our current
management by making it more difficult for stockholders to replace members of our Board, which is responsible for appointing
the members of our management. Furthermore, we have entered into a director nomination agreement with each of SVP, and
other former holders of our senior notes that provides for certain continuing nomination rights subject to conditions on share
ownership.
Our Charter designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types
of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a
favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our Charter provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of
the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any
derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by
any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to
any provision of the Delaware General Corporation Law, our Charter or our Bylaws, or (iv) any action asserting a claim against
us or any director or officer or other employee of ours governed by the internal affairs doctrine, in each such case subject to
such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein.
The exclusive forum provision would not apply to suits brought to enforce any liability or duty created by the Securities
Act of 1933, as amended (the “Securities Act”), or the Exchange Act or any other claim for which the federal courts have
exclusive jurisdiction. To the extent that any such claims may be based upon federal law claims, Section 27 of the Exchange
Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or
the rules and regulations thereunder. Furthermore, Section 22 of the Securities Act creates concurrent jurisdiction for federal
and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations
thereunder.
The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar
governing documents has been challenged in legal proceedings, and it is possible that a court could find the choice of forum
provisions contained in our Charter to be inapplicable or unenforceable, including with respect to claims arising under the U.S.
federal securities laws.
Any person or entity purchasing or otherwise holding any interest in shares of our capital stock will be deemed to have
notice of, and consented to, the provisions of our Charter described in the preceding sentence. This choice of forum provision
may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors,
officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to
find these provisions of our Charter inapplicable to, or unenforceable in respect of, one or more of the specified types of actions
or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could
adversely affect our business, financial condition or results of operations.
32
33
conditions include prices based on either the preceding 12-months' average price based on closing prices on the first day of
each month, or prices defined by existing contractual arrangements.
Proved Undeveloped (PUD) Locations - A location containing proved undeveloped reserves.
PV-10 Value - The estimated future net revenues to be generated from the production of proved reserves discounted to present
value using an annual discount rate of 10%. These amounts are calculated net of estimated production costs and future
development costs, using prices based on either the preceding 12-months' average price based on closing prices on the first day
of each month, or prices defined by existing contractual arrangements, without escalation and without giving effect to non-
property related expenses, such as general and administrative ("G&A") expenses, debt service, future income tax expense, or
depreciation, depletion, and amortization. PV-10 Value is a non-GAAP measure and its use is explained under “Item 1& 2.
Business and Properties - Oil and Natural Gas Reserves” above in this Form 10-K.
Reserves - Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically
producible, as of a given date, by application of development projects to known accumulations.
Reservoir - A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural
gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Spot Market Price - The cash market price without reduction for expected quality, transportation and demand adjustments.
Standardized Measure - The present value, discounted at 10% per year, of estimated future net revenues from the production
of proved reserves, computed by applying sales prices and deducting the estimated future costs to be incurred in developing,
producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing
economic conditions). Future income taxes are calculated by applying the statutory federal and state income tax rate to pre-tax
future net cash flow, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil
and natural gas operations. Sales prices were prepared using average hydrocarbon prices equal to the unweighted arithmetic
average of hydrocarbon prices on the first day of each month within the 12-month period preceding the reporting date (except
for consideration of price changes to the extent provided by contractual arrangements).
Undeveloped Oil and Gas Reserves - Oil and natural gas reserves of any category that are expected to be recovered from new
wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
WTI - West Texas Intermediate.
Item 3. Legal Proceedings
In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as
operator of oil and natural gas wells. In our opinion, the outcome of any such currently pending legal actions will not have a
material adverse effect on our financial position or results of operations.
Item 4. Mine Safety Disclosures
Not Applicable.
Item 1B. Unresolved Staff Comments
None.
Glossary of Abbreviations and Terms
The following abbreviations and terms have the indicated meanings when used in this report:
ASC - Accounting Standards Codification.
Bbl - Barrel or barrels of oil.
Bcf - Billion cubic feet of natural gas.
Bcfe - Billion cubic feet of natural gas equivalent (see Mcfe).
Boe - Barrels of oil equivalent.
Completion - Preparation of a well bore and installation of permanent equipment for production of oil, natural gas or NGLs or,
in the case of a dry well, reporting to the appropriate authority that the well has been abandoned.
Condensate - Liquid hydrocarbons that are found in natural gas wells and condense when brought to the well surface.
Condensate is used synonymously with oil.
Differential - An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the
quality and/or location of oil or natural gas.
Developed Oil and Gas Reserves - Oil and natural gas reserves of any category that can be expected to be recovered through
existing wells with existing equipment and operating methods.
Development Well - A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic
horizon known to be productive.
Dry Well - An exploratory or development well that is not a producing well.
DUC - A well that has been drilled and has not yet been completed
Exploratory Well - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of
oil or natural gas in another reservoir.
FASB - The Financial Accounting Standards Board.
Field - An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual
geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both
the surface and the underground productive formations.
Gross Acre - An acre in which a working interest is owned. The number of gross acres is the total number of acres in which a
working interest is owned.
Gross Well - A well in which a working interest is owned. The number of gross wells is the total number of wells in which a
working interest is owned.
MBbl - Thousand barrels of oil.
MBoe - Thousand barrels of oil equivalent.
Mcf - Thousand cubic feet of natural gas.
Mcfe - Thousand cubic feet of natural gas equivalent, which is determined using the ratio of one barrel of oil, condensate, or
natural gas liquids to 6 Mcf of natural gas.
MMBbl - Million barrels of oil.
MMBtu - Million British thermal units, which is a heating equivalent measure for natural gas and is an alternate measure of
natural gas reserves, as opposed to Mcf, which is strictly a measure of natural gas volumes. Typically, prices quoted for natural
gas are designated as price per MMBtu, the same basis on which natural gas is contracted for sale.
MMcf - Million cubic feet of natural gas.
MMcfe - Million cubic feet of natural gas equivalent (see Mcfe).
Net Acre - A net acre is deemed to exist when the sum of fractional working interests owned in gross acres equals one. The
number of net acres is the sum of fractional working interests owned in gross acres expressed as whole numbers and fractions
thereof.
Net Well - A net well is deemed to exist when the sum of fractional working interests owned in gross wells equals one. The
number of net wells is the sum of fractional working interests owned in gross wells expressed as whole numbers and fractions
thereof.
NGL - Natural gas liquid.
NYMEX - The New York Mercantile Exchange.
Producing Well - An exploratory or development well found to be capable of producing either oil or natural gas in sufficient
quantities to justify completion as an oil or natural gas well.
Proved Oil and Gas Reserves - Those quantities of oil and 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. For reserves calculations economic
34
35
PART II
Item 6. [Reserved]
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Common Stock
SilverBow's common stock is traded on the New York Stock Exchange under the symbol “SBOW.” Since inception, no
cash dividends have been declared on the Company's common stock. Cash dividends are restricted under the terms of
SilverBow's credit agreements, and the Company presently intend to continue a policy of using retained earnings for expansion
of its business.
SilverBow had approximately 99 stockholders of record as of January 31, 2022.
Stock Repurchase
There were no repurchases of the Company's common stock during the fourth quarter of 2021.
Unregistered Sales of Equity Securities and Use of Proceeds
Except as previously disclosed in a Quarterly Report on Form 10-Q or Current Report on Form 8-K, no unregistered sales
of our common stock were made during the fiscal year ended December 31, 2021.
36
37
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion and analysis in conjunction with the Company's financial information and its
audited consolidated financial statements and accompanying notes for the years ended December 31, 2021 and 2020, included
in this Form 10-K. The following information contains forward-looking statements; see “Forward-Looking Statements” on page
4 of this report.
Operational Results
The Company continues to optimize completion techniques in order to enhance well performance across its portfolio. The
following table and discussion highlights SilverBow's drilling and completion schedule for 2021:
Fields
Artesia
AWP
Fasken
Atascosa
Eastern Eagle Ford
Southern Eagle Ford Gas
Other (1)
Total
(1) Other includes non-core properties.
Net Acreage
2021
Production
(Mcfe/d)
Gas as % of
2021
Production
2021 Net
Wells Drilled
2021 Net
Wells
Completed
12,105
53,078
10,083
4,947
19,768
36,800
16,325
48,964
25,237
117,652
723
1,246
18,448
1,739
153,106
214,009
40 %
37 %
100 %
9 %
26 %
99 %
25 %
77 %
9
1
6
—
—
—
2
18
9
1
12
—
—
—
2
24
During the fourth quarter of 2021, the Company completed and brought five net wells online. There was minimal drilling
activity in the fourth quarter related to one gross non-operated well. For the full year, SilverBow drilled 18 net wells and
completed and brought online 24 net wells.
The Company finished drilling one well in its Webb County Gas area in January 2021 and released its one drilling rig
thereafter as part of a planned pause in development activity. In April 2021, SilverBow elected to accelerate and expand its
planned mid-year liquids development program. This decision was based on favorable commodity prices and completion
activity running ahead of schedule and under budget on development projects during the year. The Company’s liquids
development was focused primarily on its La Salle Condensate and McMullen Oil areas and comprised 11 net wells drilled and
completed during the year. Additionally, five net Webb County Gas wells were incorporated in the expanded mid-year
development and drilled in the third quarter of 2021. The drilling and completion activity over the second and third quarters
drove production growth and higher cash flow in the second half of the year. SilverBow released its sole drilling rig in
September 2021, and had no operated activity until the resumption of drilling at its Webb County Gas area in late December
2021.
In total the Company drilled six net operated wells in its Webb County Gas area in 2021. Of these, three net wells were in
the Austin Chalk, a zone which the Company has been focused on proving up for future development. The Austin Chalk wells
in Webb County continue to exceed expectations and exhibit strong commercial economics. SilverBow brought a fourth Austin
Chalk well online in early 2022 in its Webb County Gas area, further enhancing its ability to deliver consistent and repeatable
results across the position. The first well has produced approximately 3.7 billion cubic feet of natural gas in its first year. The
Austin Chalk wells averaged 7,500 foot laterals with drilling and completion (“D&C”) costs of $727 per lateral foot, which
compares favorably to recent Austin Chalk results from nearby operators. Given that D&C activity in the Austin Chalk to-date
has focused on single-pad, delineation wells, SilverBow expects to realize greater cost efficiencies for future full-scale
development. In the La Mesa and Fasken fields, multi-zone pad development efficiencies led to lower drilling and completion
costs as the Company continued to leverage its technical experience and long operating history in the area. SilverBow also
elected to participate in three gross non-operated wells in Webb County which were drilled in the second half of 2021 and will
benefit from production in early 2022.
The Company closed three acquisitions in the second half of 2021. From the closing of each of these respective
acquisitions, in aggregate, SilverBow added 286 barrels per day (“Bbls/d”) of liquids and 4.5 million cubic feet per day
(“MMcf/d”) to the Company's full year net production. Additionally, the acquired assets provided SilverBow a deep runway of
future oil and gas development locations in the Eagle Ford and Austin Chalk. The Company added more than 200 net drilling
locations from acquired assets in 2021, with further inventory upside potential based on optimizations to well costs, spacing and
lateral lengths given the highly contiguous lease footprints with SilverBow's existing acreage. The Company is working to
integrate these new assets into its low cost structure and should benefit from greater operating cost synergies due to increased
size and scale. The acquisition activity in 2021 reflects a continued focus on identifying opportunities to add to core positions in
high-return areas.
SilverBow's asset management program seeks to optimize recoverability and operating costs from producing wells. The
Company proactively invests in workovers, compression and artificial lift installations and other enhancements to maintain
production output, improve its base decline and lower field operating costs. Furthermore, SilverBow prioritizes operational
safety and maintains a goal of zero total recordable incidents. The Company's production operations group recently celebrated
its five year anniversary with zero OSHA recordable accidents.
SilverBow has spent last several years positioning its inventory and development plans to be flexible. This has allowed the
Company to align with prevailing commodity prices, and to drive greater operational efficiencies by concentrating its efforts in
areas in which the team possesses deep technical expertise and experience. Across all of its operating areas in the Eagle Ford in
2021, SilverBow drilled 10% more lateral footage per day while lowering completion costs per well by 17% as compared to
2020. The Company's demonstrated success in increasing field efficiencies, reducing cycle times and lowering costs is a direct
result of its operational and supply teams working with vendors to negotiate prices and logistical considerations for the
materials used in its operations. As a result, SilverBow's drilling and completion costs per lateral foot in 2021 decreased by 13%
as compared to 2020. Although the rate of operational efficiency gains are anticipated to slow as the Company approaches field
level limitations and focuses on developing newly acquired acreage requiring potentially longer transition times, maintaining
and improving upon the efficiency gains to-date is core to SilverBow's cost mitigation efforts within an inflationary service cost
environment expected in its near-term outlook.
Cost reduction initiatives: The Company continues to focus on cost reduction measures in the areas that it can control.
These initiatives include the use of regional sand in completions, improved utilization of existing facilities, elimination of
redundant equipment and replacement of rental equipment with SilverBow-owned equipment. As previously mentioned, the
Company continues to improve its process for drilling, completing and equipping wells. SilverBow's procurement team takes a
process-oriented approach to managing the total delivered costs of purchased services by examining costs at their most granular
level. Services are routinely sourced directly from the suppliers. The Company's lease operating expenses were $27.7 million or
$0.35 per Mcfe for the year ended December 31, 2021, as compared to $21.4 million or $0.32 per Mcfe for the year ended
December 31, 2020. The increase in costs was due to incremental expenses related to Winter Storm Uri, higher salt water
disposal, higher compression costs and higher utilities. These increases were partially mitigated by lower treating costs.
SilverBow's net G&A expenses were $21.8 million or $0.28 per Mcfe for the year ended December 31, 2021. After
deducting $4.6 million of share-based compensation, cash G&A expenses (a non-GAAP financial measure) were $17.2 million
or $0.22 per Mcfe for the year ended December 31, 2021. This compares to net G&A expenses of $22.6 million or $0.34 per
Mcfe for the same period in 2020. After deducting $4.6 million of share-based compensation, cash G&A expenses (a non-
GAAP financial measure) were $18.0 million or $0.27 per Mcfe for the same period in 2020.
The Company continued to maintain a safe working environment while implementing these cost-reduction efforts.
SilverBow's corporate total recordable incident rate was 0.15 incidents per 1.3 million work hours in 2021.
The Company reports cash G&A because it believes this measure is commonly used by management, analysts and
investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition,
SilverBow believes cash G&A expenses are used by analysts and others in valuation, comparison and investment
recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based
compensation programs which can vary substantially from company to company. Cash G&A expenses should not be
considered as an alternative to, or more meaningful than, total G&A expenses.
38
39
Summary of 2021 Financial Results
•
•
•
Revenues and net income (loss): The Company's oil and gas revenues were $407.2 million and $177.4 million for the years
ended December 31, 2021 and 2020, respectively. Revenues were higher due to increased production volumes and overall
higher commodity pricing. The Company had net income of $86.8 million and a net loss of $309.4 million for the years
ended December 31, 2021 and 2020, respectively. The increase was primarily due to higher revenues due to increased
production volumes and higher commodity pricing along with no non-cash impairment write-down during the current
period.
Capital expenditures: The Company's capital expenditures (excluding acquisitions) on an accrual basis were $130.5 million
and $95.2 million for the years ended December 31, 2021 and 2020, respectively. The expenditures for the years ended
December 31, 2021 and 2020, were primarily driven by continued legacy development. These expenditures were funded by
cash flow from operations and borrowings under our Credit Facility.
Acquisitions: The Company closed three acquisitions in the second half of 2021. These acquisitions, in aggregate, added
286 barrels per day of liquids and 4.5 million cubic feet per day to SilverBow’s full year net production. This represents
less than 3% of the Company's full year 2021 net production. SilverBow expects these acquisitions to comprise a greater
percentage of its full year 2022 net production with a full year's contribution. In total the Company paid $50.6 million in
cash and issued $83.5 million in equity related to these transactions.
• Working capital: The Company had a working capital deficit of $65.8 million and $23.1 million at December 31, 2021 and
December 31, 2020, respectively. The working capital computation does not include available liquidity through our Credit
Facility.
•
Cash Flow: For the year ended December 31, 2021, the Company generated cash from operating activities of $215.7
million, of which $6.2 million was attributable to changes in working capital. Cash used for property additions was $133.6
million. This included $4.0 million attributable to a net decrease of capital related payables and accrued costs. Additionally,
$1.1 million was paid during the year for property sale obligations related to the sale of our former Bay De Chene field.
The Company’s net repayments under its revolving Credit Facility were $3.0 million for the year ended December 31,
2021 and repayments under its Second Lien Facility were $50.0 million.
For the year ended December 31, 2020, the Company generated cash from operating activities of $165.2 million, of which
$7.1 million was attributable to changes in working capital. Cash used for property additions was $114.7 million. This
included $19.4 million attributable to a net decrease of capital related to payables and accrued costs. Additionally, $0.8
million was paid during the year for property sale obligations related to the sale of our former Bay De Chene field. The
Company's net repayments under its Credit Facility were $49.0 million for the year ended December 31, 2020.
Liquidity and Capital Resources
SilverBow's primary use of cash has been to fund capital expenditures to develop its oil and gas properties. As of
December 31, 2021, the Company’s liquidity consisted of approximately $1.1 million of cash-on-hand and $233.0 million in
available borrowings on its Credit Facility, which had a $460.0 million borrowing base. SilverBow's 2022 capital budget, which
is expected to be in the range of $180-$200 million, provides for drilling 39 gross (33 net) horizontal wells and is expected to be
funded primarily from operating cash flow. Management believes the Company has sufficient liquidity to meet its obligations
through at least the first quarter of 2023 and execute its long-term development plans. See Note 4 to SilverBow's consolidated
financial statements for more information on its Debt Facilities.
ATM Program. On August 13, 2021, the Company entered into an equity distribution agreement pursuant to which the
SilverBow may sell, from time to time in the open market, shares of the Company’s common stock, having aggregate proceeds
of up to $40.0 million (the “ATM Program”). SilverBow intends to use the net proceeds from any sales through the ATM
Program for general corporate purposes, including, but not limited to, financing of capital expenditures, repayment or
refinancing of outstanding debt, financing acquisitions or investments, financing other business opportunities, and general
working capital purposes. During the year ended December 31, 2021 (from August 13, 2021 through December 31, 2021), the
Company sold 1,222,209 shares of common stock for net proceeds of $27.0 million after deducting sales agents' commissions
and other related expenses.
Senior Secured Second Lien Notes. Effective November 12, 2021, SilverBow entered into the Second Amendment to the
Note Purchase Agreement, which extended the maturity date from December 15, 2024 to December 15, 2026 subject to paying
down the principal amount of the Second Lien from $200.0 million to $150.0 million. The Company made the $50 million
redemption of the Second Lien Notes on November 29, 2021. SilverBow accounted for this paydown as a debt modification
and incurred approximately $0.1 million in third party fees in connection with the amendment. The unamortized debt issuance
cost and discount on the Second Lien Notes will be amortized through the new maturity date of December 15, 2026.
Contractual Commitments and Obligations
Our contractual commitments for the next five years and thereafter are shown below as of December 31, 2021 (in
thousands):
Non-cancelable operating leases
Gas transportation and processing (1)
Interest cost (2)
Long-term debt
Other contractual commitments (3)
2022
2023
2024
2025
2026
Thereafter
Total
$
7,757 $
6,468 $
1,200 $
803 $
689 $
539 $
17,456
1,802
2,730
1,718
1,171
—
23,304
23,370
16,567
13,664
13,176
—
—
7,421
90,081
—
477
— 227,000
— 150,000
—
377,000
—
—
—
—
—
477
Total
$ 33,340 $ 32,568 $ 246,485 $ 15,638 $ 163,865 $
539 $ 492,435
(1) Amounts shown represent fees for the minimum delivery obligations. Any amount of transportation utilized in excess of the minimum will reduce future
year obligations. The Company's production and reserves are currently sufficient to fulfill the current minimum delivery obligations.
(2) Interest on our Credit Facility is estimated using the weighted average interest rate of 4.34% for the quarter ended December 31, 2021, while interest on our
Second Lien is estimated using LIBOR plus 7.5%. See Note 4 of these consolidated financial statements in this Form 10-K for more information. Actual
interest rate is variable over the term of the facility.
(3) Amount shown primarily for obligation under Bay De Chene sales contract.
Off-Balance Sheet Arrangements
As of December 31, 2021, we had no off-balance sheet arrangements requiring disclosure pursuant to article 303(a) of
Regulation S-K.
Proved Oil and Gas Reserves
During 2021, our reserves increased by approximately 309.4 Bcfe due to increases in our natural gas reserves primarily
from our Austin Chalk area and contributions from acquisitions closed in the second half of 2021. As of December 31, 2021,
46% of our total proved reserves were proved developed, compared with 46% and 41% at year-end 2020 and 2019.
At December 31, 2021, our proved reserves were 1,415.8 Bcfe with a Standardized Measure of $1.6 billion, which is an
increase of approximately $1.0 billion, or 204%, from the prior year-end levels. In 2021, our proved natural gas reserves
increased 207.3 Bcf, or 22%, while our proved oil reserves increased 11.8 MMBbl, or 94%, and our NGL reserves increased
5.2 MMBbl, or 38%, for a total equivalent increase of 309.4 Bcfe, or 28%.
We have added proved reserves primarily through our drilling activities and acquisitions, including 359.4 Bcfe added in
2021. We obtained reasonable certainty regarding these reserve additions by applying the same methodologies that have been
used historically in this area.
We use the preceding 12-month's average price based on closing prices on the first business day of each month, adjusted
for price differentials, in calculating our average prices used in the Standardized Measure calculation. Our average natural gas
price used in the Standardized Measure calculation for 2021 was $3.75 per Mcf. This average price increased from the average
price of $2.13 per Mcf used for 2020. Our average oil price used in the calculation for 2021 was $63.98 per Bbl. This average
price increased from the average price of $37.83 per Bbl used in the calculation for 2020. Our average NGL price used in the
calculation for 2021 was $25.29 per Bbl. This average price increased from the average price of $11.66 per Bbl used in the
calculation for 2020.
40
41
Results of Operations
Revenues — Years Ended December 31, 2021 and 2020
2021 - Our oil and gas sales in 2021 increased by 130% compared to revenues in 2020, primarily due to overall higher
commodity pricing and higher production volumes. Average oil prices we received were 78% higher than those received during
2020, while natural gas prices were 115% higher and NGL prices were 113% higher.
Crude oil production was 11% and 14% of our production volumes for the years ended December 31, 2021 and 2020,
respectively, while crude oil sales revenues were 24% and 33% of oil and gas sales revenue for the years ended December 31,
2021 and 2020, respectively.
Natural gas production was 77% and 76% of our production volumes for the years ended December 31, 2021 and 2020,
respectively, while natural gas sales revenues were 66% and 59% and of oil and gas sales for the years ended December 31,
2021 and 2020, respectively.
NGL production was 12% and 10% of our production volumes for the years ended December 31, 2021 and 2020,
respectively, while NGL sales were 10% and 8% of oil and gas sales for the years ended December 31, 2021 and 2020,
respectively.
The following tables provide information regarding the changes in the sources of our oil and gas sales and volumes for the
years ended December 31, 2021 and 2020:
Fields
Oil and Gas Sales (In Millions)
Net Oil and Gas Production
Volumes (MMcfe)
Artesia
AWP
Fasken
Atascosa
Eastern Eagle Ford
Southern Eagle Ford Gas
Other
Total
$
2021
110.2 $
64.3
194.6
2.9
3.8
27.7
3.7
$
407.2 $
2020
42.1
50.5
72.0
—
—
10.8
1.9
177.3
2021
17,872
9,211
42,943
264
455
6,734
634
78,113
2020
13,299
12,432
35,410
—
—
4,935
724
66,800
Our sales volume increase from 2020 to 2021 was primarily due to higher natural gas and NGL production, partially offset
by lower crude oil production.
The following table provides additional information regarding our oil and gas sales, by commodity type, as well as the
effects of our hedging activities for derivative contracts held to settlement for the years ended December 31, 2021 and 2020 (in
thousands, except per-dollar amounts):
Year Ended December
31, 2021
Year Ended December
31, 2020
Production volumes:
Oil (MBbl) (1)
Natural gas (MMcf)
Natural gas liquids (MBbl) (1)
Total (MMcfe)
Oil, natural gas and natural gas liquids sales:
Oil
Natural gas
Natural gas liquids
Total
Average realized price:
Oil (per Bbl)
Natural gas (per Mcf)
Natural gas liquids (per Bbl)
Average per Mcfe
Price impact of cash-settled derivatives:
Oil (per Bbl)
Natural gas (per Mcf)
Natural gas liquids (per Bbl)
Average per Mcfe
Average realized price including impact of cash-settled derivatives:
Oil (per Bbl) (2)
Natural gas (per Mcf)
Natural gas liquids (per Bbl)
Average per Mcfe
1,462
60,510
1,472
78,113
98,607 $
267,687
40,906
407,200 $
67.46 $
4.42
27.78
5.21 $
(16.50) $
(0.69)
(5.07)
(0.94) $
50.96 $
3.73
22.71
4.27 $
1,521
50,988
1,114
66,800
57,651
105,234
14,500
177,386
37.89
2.06
13.02
2.66
13.27
0.38
—
0.59
51.16
2.44
13.02
3.25
$
$
$
$
$
$
$
$
In 2021, our $229.8 million, or 130%, increase in oil, NGL, and natural gas sales resulted from:
(1) Oil and natural gas liquids are converted at the rate of one barrel to six Mcfe.
(2) Excludes the impact of the $38.3 million for derivative contracts monetized in the first quarter of 2020.
•
•
Volume variances that had a $22.0 million favorable impact on sales, with a $2.3 million decrease due to the 0.1
million Bbl decrease in oil production volumes, a $19.7 million increase due to the 9.5 Bcf increase in natural gas
production volumes and a $4.7 million increase due to the 0.4 million Bbl increase in NGL production volumes.
Price variances that had a $207.8 million favorable impact on sales, with an increase of $142.8 million due to the
114% increase in natural gas prices received, an increase of $43.2 million due to the 78% increase in oil prices
received and an increase of $21.7 million due to the 113% increase in NGL prices received.
For the years ended December 31, 2021 and 2020 we recorded net losses of $123 million and net gains of $61.3 million,
respectively, related to our derivative activities. Included in our gain during the year ended December 31, 2020 was
$38.3 million for monetized derivative contracts received in the first quarter of 2020. The change was driven primarily by
changes in commodity pricing. This activity is recorded in “Net gain (loss) on commodity derivatives” on the accompanying
consolidated statements of operations in this Form 10-K.
42
43
Costs and Expenses
The following table provides additional information regarding our expenses for the years ended December 31, 2021 and
2020:
Costs and Expenses
General and administrative, net
Depreciation, depletion, and amortization
Accretion of asset retirement obligation
Lease operating expenses
Workovers
Transportation and gas processing
Severance and other taxes
Interest expense, net
Write-down of oil and gas properties
Year Ended
December 31, 2021
Year Ended
December 31, 2020
$
21,799 $
68,629
306
27,206
514
24,145
19,307
29,129
—
22,608
64,564
354
21,360
8
20,649
10,514
31,228
355,948
Our costs and expenses during 2021 versus 2020 were as follows:
General and Administrative Expenses, Net. These expenses on a per Mcfe basis were $0.28 and $0.34 for the years ended
December 31, 2021 and 2020, respectively. The decrease per Mcfe was due to higher production while the decrease in costs
was primarily due to lower salaries and burdens, temporary labor expenses and legal fees. Included in general and
administrative expenses is $4.6 million in share-based compensation for both the years ended December 31, 2021 and 2020.
Depreciation, Depletion and Amortization (“DD&A”). These expenses on a per Mcfe basis were $0.88 and $0.97 for the
years ended December 31, 2021 and 2020, respectively. Our full year 2020 DD&A rate was impacted by non-cash impairment
writedowns in the first half of 2020. Our DD&A rate is impacted by the timing and amount or reserve additions and the future
development costs associated with those additions, revisions of previous reserve estimates, non-cash impairment writedowns,
acquisitions and dispositions of proved reserves and the amount of costs subject to amortization.
Lease Operating Expenses. These expenses on a per Mcfe basis were $0.35 and $0.32 for the years ended December 31,
2021 and 2020, respectively. The increase in costs is due to higher compression costs and salt water disposal costs, partially
offset by lower treating costs.
Transportation and gas processing. These expenses all related to natural gas and NGL sales. These expenses on a per Mcfe
basis were $0.31 for both the years ended December 31, 2021 and 2020.
Severance and Other Taxes. In general, severance taxes are based upon current year commodity prices and production
whereas ad valorem taxes are based upon the value of oil and gas reserves at the beginning of the year. Severance taxes are paid
on produced oil and natural gas based on a percentage of revenues from products sold. The increase in severance and other
taxes is directly attributable to the increase in oil and gas revenues associated with higher commodity prices. Our ad valorem
expense included in Severance and other taxes remained relatively consistent from 2020 to 2021. Severance and other taxes, as
a percentage of oil and gas sales, were approximately 4.7% and 5.9% for the years ended December 31, 2021 and 2020,
respectively.
Interest Expense. Our gross interest expense was $29.1 million and $31.2 million for the years ended December 31, 2021
and 2020, respectively. The decrease in gross interest was primarily due to decreased borrowings. There was no capitalized
interest for both of the years ended December 31, 2021 and 2020.
Write-down of oil and gas properties. There was no impairment for the year ended December 31, 2021. Due to the effects
of pricing, we reported a non-cash impairment write-down of $355.9 million impairment for the year ended December 31,
2020.
Income Taxes. The Company recorded an income tax provision of $6.4 million for the year ended December 31, 2021
which was primarily attributable to deferred federal income tax expense. In March and April 2020, the COVID-19 pandemic
caused volatility in the market price for crude oil due to the disruption of global supply and demand. In response to these
market conditions and given the decline in oil prices and economic outlook for the Company, management determined that it
was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items
and other deferred tax assets and, accordingly, recorded a full valuation allowance in the second quarter of 2020 to offset its net
deferred tax assets in excess of deferred tax liabilities. This resulted in tax expense of $21.2 million in the second quarter of
2020. Our income tax provision of $20.9 million for the year ended December 31, 2020 is inclusive of state income tax benefit
of $1.8 million.
Critical Accounting Policies and New Accounting Pronouncements
Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment
costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and
acquisition of oil and natural gas reserves are capitalized including internal costs incurred that are directly related to these
activities and which are not related to production, general corporate overhead, or similar activities. Future development costs
are estimated on a property-by-property basis based on current economic conditions and are amortized to expense as our
capitalized oil and natural gas property costs are amortized. We compute the provision for DD&A of oil and natural gas
properties using the unit-of-production method.
The costs of unproved properties not being amortized are assessed quarterly, on a property-by-property basis, to determine
whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling
results, lease expiration dates, current oil and gas industry conditions, international economic conditions, capital availability,
and available geological and geophysical information. As these factors may change from period to period, our evaluation of
these factors will change. Any impairment assessed is added to the cost of proved properties being amortized.
The calculation of the provision for DD&A requires us to use estimates related to quantities of proved oil and natural gas
reserves and estimates of the impairment of unproved properties. The estimation process for both reserves and the impairment
of unproved properties is subjective, and results may change over time based on current information and industry conditions.
We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of
risks and uncertainties that may cause actual results to differ materially from such estimates.
Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties
(including natural gas processing facilities, capitalized asset retirement obligations and deferred income taxes, and excluding
the recognized asset retirement obligation liability) is limited to the sum of the estimated future net revenues from proved
properties (excluding cash outflows from recognized asset retirement obligations, including future development and
abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day
of each month, adjusted for price differentials, discounted at 10%, and the lower of cost or fair value of unproved properties)
adjusted for related income tax effects. At December 31, 2021, the discounted present value of our estimated total proved
reserves adjusted for related income tax effects exceeded our unamortized cost of oil and natural gas properties by
approximately $0.9 billion.
We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a
number of risks and uncertainties that may cause actual results to differ materially from such estimates.
If future capital expenditures outpace future discounted net cash flow in our reserve calculations, if we have significant
declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flow from
proved oil and natural gas reserves) or if oil or natural gas prices remain depressed or continue to decline, it is possible that non-
cash write-downs of our oil and natural gas properties will occur in the future. We cannot control and cannot predict what future
prices for oil and natural gas will be, thus we cannot estimate the amount or timing of any potential future non-cash write-down
of our oil and natural gas properties due to decreases in oil or natural gas prices.
New Accounting Pronouncements. In March 2020, the FASB issued ASU No. 2020-03. ASU 2020-03 improves and
clarifies various financial instruments topics, including the current expected credit loss standard (“CECL”). ASU 2020-03
includes seven different issues that describe the areas of improvement and the related amendments to GAAP, intended to make
the standards easier to understand and apply by eliminating inconsistencies and providing clarifications. This guidance is
effective beginning on January 1, 2023 for smaller reporting companies. We are still assessing the requirements to determine
the impact of this guidance on our consolidated financial statements.
In August 2020, the FASB issued ASU No. 2020-06. This ASU simplifies the accounting for certain financial instruments
with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. For
convertible instruments with conversion features that are not accounted for as derivatives under ASC 815 or do not result in
substantial premiums accounted for as paid-in capital, the convertible instrument's embedded conversion features are no longer
44
45
separated from the host contract. Consequently, and as long as no other feature requires bifurcation and recognition as a
derivative, the convertible instrument is accounted for as a single liability measured at its amortized cost. This ASU also
amends the impact of convertible instruments on the calculation of diluted earnings per share (EPS) and adds several new
disclosure requirements. The ASU is effective for fiscal years beginning after December 15, 2021. The ASU can be adopted on
either a fully retrospective or modified retrospective basis. The adoption of this guidance is not expected to have a material
impact on the Company’s consolidated financial statements or disclosures.
In May 2021, the FASB issued ASU 2021-04. This guidance provides clarification and reduces diversity in an issuer’s
accounting for modifications or exchanges of freestanding equity-classified written call options (such as warrants) that remain
equity classified after modification or exchange. An issuer measures the effect of a modification or exchange as the difference
between the fair value of the modified or exchanged warrant and the fair value of that warrant immediately before modification
or exchange. The ASU introduces a recognition model that comprises four categories of transactions and the corresponding
accounting treatment for each category (equity issuance, debt origination, debt modification, and modifications unrelated to
equity issuance and debt origination or modification). This guidance is effective for all entities for fiscal years beginning after
December 15, 2021, including interim periods within those fiscal years. The adoption of this guidance is not expected to have a
material impact on the Company’s consolidated financial statements or disclosures.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Risk. Our major market risk exposure is the commodity pricing applicable to our oil and natural gas
production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for
crude oil and spot prices applicable to natural gas. This commodity pricing volatility has continued with unpredictable price
swings in recent periods.
Our price-risk management policy permits the utilization of agreements and financial instruments (such as futures, forward
contracts, swaps and options contracts) to mitigate price risk associated with fluctuations in oil and natural gas prices. We do
not utilize these agreements and financial instruments for trading and only enter into derivative agreements with banks in our
Credit Facility. For additional discussion related to our price-risk management policy, refer to Note 5 of the consolidated
financial statements in this Form 10-K.
Customer Credit Risk. We are exposed to the risk of financial non-performance by customers. Our ability to collect on
sales to our customers is dependent on the liquidity of our customer base. Continued volatility in both credit and commodity
markets may reduce the liquidity of our customer base. To manage customer credit risk, we monitor credit ratings of customers
and from certain customers we also obtain letters of credit, parent company guarantees if applicable, and other collateral as
considered necessary to reduce risk of loss. Due to availability of other purchasers, we do not believe the loss of any single oil
or natural gas customer would have a material adverse effect on our results of operations.
Concentration of Sales Risk. For the year ended December 31, 2021, approximately 26%, 10%, 15%, 16% and 12% of
our oil and gas receipts were accounted for by Kinder Morgan, Inc. (“Kinder Morgan”), Plains Marketing, LP (“Plains
Marketing”), Twin Eagle Resource Management LLC (“Twin Eagle”), Trafigura US, Inc (“Trafigura”) and Shell Trading
(“Shell Trading”). There were no other purchasers who individually accounted for 10% or more of our oil and gas receipts. We
expect to continue these relationships in the future. We believe that the risk of these unsecured receivables is mitigated by the
size, reputation and nature of the businesses and the availability of other purchasers in the areas where we operate.
Interest Rate Risk. At December 31, 2021, we had a combined $377.0 million drawn under our Credit Facility and our
Second Lien Notes, which bear a floating rate of interest depending on the level of the borrowing base and the borrowing base
loans outstanding and therefore is susceptible to interest rate fluctuations. These variable interest rate borrowings are impacted
by changes in short-term interest rates. A hypothetical one-percentage point increase in interest rates on our borrowings
outstanding under our Credit Facility and Second Lien Notes at December 31, 2021 would increase our annual interest expense
by $3.8 million.
46
47
Item 8. Financial Statements and Supplementary Data
Page
Management's Report on Internal Control Over Financial Reporting
Management's Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements (BDO USA, LLP;
Houston, Texas; PCAOB ID#243)
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Stockholders' Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Supplementary Information
Management of SilverBow Resources is responsible for establishing and maintaining adequate internal control over
financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. The Company's internal control over
financial reporting is a process designed by, or under the supervision of, the Company's Chief Executive Officer and Chief
Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the
Company's financial statements for external purposes in accordance with U. S. generally accepted accounting principles.
Management of the Company assessed the effectiveness of the Company's internal control over financial reporting as of
December 31, 2021. In making this assessment, management used the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO criteria) (2013 framework) in Internal Control-Integrated Framework.
Based on our assessment and those criteria, management determined that the Company maintained effective internal control
over financial reporting as of December 31, 2021. BDO USA, LLP, our independent registered public accounting firm, has
independently assessed the effectiveness of our internal control over financial reporting and its report is included below.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control
objectives. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
49
50
51
53
54
55
56
57
79
48
49
Report of Independent Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm
Shareholders and Board of Directors
SilverBow Resources, Inc.
Houston, Texas
Stockholders and Board of Directors
SilverBow Resources, Inc.
Houston, Texas
Opinion on Internal Control over Financial Reporting
Opinion on the Consolidated Financial Statements
We have audited SilverBow Resources, Inc.’s (the “Company’s”) internal control over financial reporting as of December
31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all
material respects, effective internal control over financial reporting as of December 31, 2021, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (“PCAOB”), the consolidated balance sheets of the Company as of December 31, 2021 and 2020, the related
consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended, and the related notes and
our report dated March 3, 2022 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report
on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control
over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be
independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those
standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control
over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and
operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures
as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ BDO USA, LLP
Houston, Texas
March 3, 2022
We have audited the accompanying consolidated balance sheets of SilverBow Resources, Inc. (the “Company”) as of
December 31, 2021 and 2020, the related consolidated statements of operations, stockholders’ equity, and cash flows for the
years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the
consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31,
2021 and 2020, and the results of its operations and its cash flows for the years then ended, in conformity with accounting
principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (“PCAOB”), the Company's internal control over financial reporting as of December 31, 2021, based on criteria
established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the
Treadway Commission (“COSO”) and our report dated March 3, 2022 expressed an unqualified opinion thereon.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to
express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm
registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be
independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material
misstatement, whether due to error or fraud.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included
examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits
also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating
the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our
opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial
statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or
disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or
complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated
financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate
opinions on the critical audit matter or on the accounts or disclosures to which it relates.
Proved Oil and Natural Gas Reserves Estimation and Impact on Depreciation, Depletion and Amortization (“DD&A”)
Expense and Full-Cost Ceiling Test Impairment Calculation Related to Proved Oil and Natural Gas Properties
As described in Note 1 to the consolidated financial statements, proved oil and natural gas reserves volumes and associated
future net cash flows directly impact the calculation of DD&A expense and the full-cost ceiling test impairment calculation.
There are numerous uncertainties inherent in estimating proved oil and natural gas reserves volumes and associated future net
cash flows including, among others, estimated future production volumes and timing of such production, pricing differentials,
lease operating expenses, and amounts and timing of capital expenditures. The accuracy of these estimates is dependent on the
quality of available data and on engineering and geological interpretation and judgment. The estimation of oil and natural gas
reserve volumes and associated future net cash flows requires management’s use of internal petroleum engineers and
independent petroleum engineers and geologists (referred to as “management’s specialists”).
50
51
We have identified the estimation of future production volumes, lease operating expenses, and amounts and timing of
future capital expenditures used to estimate oil and natural gas reserves, and the associated impact on DD&A expense and the
full-cost ceiling test impairment calculation related to proved oil and natural gas properties as a critical audit matter. Changes in
these inputs and assumptions, which all require a high degree of subjectivity, could have a material impact on the overall
estimate of proved oil and natural gas reserve volumes and associated future cash flows and the related measurement of DD&A
expense or the full-cost ceiling test impairment calculation. Auditing management’s judgment with respect to these inputs
involved a high degree of auditor judgment in the design of our audit procedures and the evaluation of the audit evidence
obtained.
The primary procedures we performed to address this critical audit matter included:
•
•
•
•
•
•
•
Testing the design and operating effectiveness of internal controls relating to management’s estimation of proved oil
and natural gas reserves.
Evaluating the professional qualifications of management’s specialists and their relationship to the Company and
making inquiries of management’s specialists regarding the process followed and judgments used to assist in
estimating the Company’s proved oil and natural gas reserves.
Comparing estimated production volumes and production decline analyses against results of actual production and
actual production decline analyses to determine the appropriateness of management’s estimates.
Evaluating the estimates of lease operating expenses used in the reserve estimates compared to historical lease
operating expenses.
Comparing the estimates of future capital expenditures used in the reserve estimates to amounts expended for recently
drilled and completed wells in similar locations.
Evaluating the Company’s evidence to support the amount of proved undeveloped properties reflected in the reserve
estimates by examining historical conversion rates and support for the Company’s intent to develop the proved
undeveloped properties.
Evaluating management’s estimates of oil and natural gas reserve volumes, lease operating expenses and future capital
expenditures against evidence obtained in other areas of the audit for consistency and reasonableness.
/s/ BDO USA, LLP
We have served as the Company's auditor since 2016.
Houston, Texas
March 3, 2022
Consolidated Balance Sheets
SilverBow Resources, Inc. (in thousands, except share amounts)
ASSETS
Current Assets:
Cash and cash equivalents
Accounts receivable, net
Fair value of commodity derivatives
Other current assets
Total Current Assets
Property and Equipment:
Property and Equipment, Full-Cost Method, including $17,090 and $28,090
of unproved property costs not being amortized
Less – Accumulated depreciation, depletion, amortization and impairment
Property and Equipment, Net
Right of use assets
Fair value of long-term commodity derivatives
Other long-term assets
Total Assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities
Fair value of commodity derivatives
Accrued capital costs
Accrued interest
Current lease liability
Undistributed oil and gas revenues
Total Current Liabilities
Long-term debt
Non-current lease liability
Deferred tax liabilities, net
Asset retirement obligations
Fair value of long-term commodity derivatives
Other long-term liabilities
Commitments and Contingencies (Note 6)
Stockholders' Equity:
December 31, 2021 December 31, 2020
$
1,121 $
49,777
2,806
1,875
55,579
1,611,953
(869,985)
741,968
16,065
201
5,641
2,118
25,850
4,821
2,184
34,973
1,343,373
(801,279)
542,094
4,366
281
1,421
$
$
819,454 $
583,135
35,034 $
47,453
7,354
697
7,222
23,577
121,337
372,825
9,090
6,516
5,526
8,585
3,043
26,991
8,171
7,324
983
3,473
11,098
58,040
424,905
951
303
4,533
2,946
424
Preferred stock, $0.01 par value, 10,000,000 shares authorized, none issued
—
—
Common stock, $0.01 par value, 40,000,000 shares authorized, 16,822,845
and 12,053,763 shares issued and 16,631,175 and 11,936,679 shares
outstanding
Additional paid-in capital
Treasury stock held, at cost, 191,670 and 117,084 shares
Retained earnings (Accumulated deficit)
Total Stockholders’ Equity
168
413,017
(2,984)
(117,669)
292,532
Total Liabilities and Stockholders’ Equity
$
819,454 $
See accompanying Notes to Consolidated Financial Statements.
121
297,712
(2,372)
(204,428)
91,033
583,135
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53
Consolidated Statements of Operations
SilverBow Resources, Inc. (in thousands, except per-share amounts)
Consolidated Statements of Stockholders’ Equity
SilverBow Resources, Inc. (in thousands, except share amounts)
Year Ended
December 31, 2021
Year Ended
December 31, 2020
Common
Stock
Additional
Paid-in
Capital
Treasury
Stock
Retained
Earnings
(Accumulat
ed Deficit)
Total
$
407,200 $
177,386
Balance, December 31, 2019
$
119 $
292,916 $
(2,282) $
104,954 $
395,707
21,799
68,629
306
27,206
514
24,145
19,307
—
161,906
22,608
64,564
354
21,360
8
20,649
10,514
355,948
496,005
Shares issued from option exercise (5 shares issued)
Purchase of treasury shares (28,731 shares)
Vesting of share-based compensation (158,726 shares)
Share-based compensation
Net Loss
Balance, December 31, 2020
—
—
2
—
—
—
—
(1)
4,797
—
—
(90)
—
—
—
—
—
—
—
—
(90)
1
4,797
(309,382)
(309,382)
$
121 $
297,712 $
(2,372) $
(204,428) $
91,033
Shares issued from option exercise (no shares)
Purchase of treasury shares (74,586 shares)
Vesting of share-based compensation (336,247 shares)
Issuance of common stock (1,222,209 shares)
Issuance pursuant to acquisitions (3,210,626 shares)
Share-based compensation
Net Income
Balance, December 31, 2021
See accompanying Notes to Consolidated Financial Statements.
—
—
3
12
32
—
—
—
—
(3)
26,944
83,490
4,874
—
—
(612)
—
—
—
—
—
—
—
—
—
—
—
86,759
—
(612)
—
26,956
83,522
4,874
86,759
$
168 $
413,017 $
(2,984) $
(117,669) $
292,532
Revenues:
Oil and gas sales
Operating Expenses:
General and administrative, net
Depreciation, depletion, and amortization
Accretion of asset retirement obligations
Lease operating expense
Workovers
Transportation and gas processing
Severance and other taxes
Write-down of oil and gas properties
Total Operating Expenses
Operating Income (Loss)
245,294
(318,619)
Non-Operating Income (Expense)
Net gain (loss) on commodity derivatives
Interest expense, net
Other income (expense), net
(123,018)
(29,129)
10
61,304
(31,228)
72
Income (Loss) Before Income Taxes
93,157
(288,471)
Provision (Benefit) for Income Taxes
6,398
20,911
Net Income (Loss)
Per Share Amounts:
Basic: Net Income (Loss)
Diluted: Net Income (Loss)
Weighted Average Shares Outstanding - Basic
Weighted Average Shares Outstanding - Diluted
See accompanying Notes to Consolidated Financial Statements.
$
$
$
86,759 $
(309,382)
6.61 $
(25.99)
6.42 $
(25.99)
13,118
13,520
11,902
11,902
54
55
Consolidated Statements of Cash Flows
SilverBow Resources, Inc. (in thousands)
Cash Flows from Operating Activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating
activities-
Write-down of oil and gas properties
Depreciation, depletion, and amortization
Accretion of asset retirement obligations
Deferred income tax expense (benefit)
Share-based compensation expense
(Gain) Loss on derivatives, net
Cash settlements (paid) received on derivatives
Settlements of asset retirement obligations
Write-down of debt issuance cost
Other
Change in operating assets and liabilities-
(Increase) decrease in accounts receivable and other assets
Increase (decrease) in accounts payable and accrued liabilities
Increase (decrease) in income taxes payable
Increase (decrease) in accrued interest
Year Ended
December 31,
2021
Year Ended
December 31,
2020
$
86,759 $
(309,382)
—
68,629
306
6,212
4,645
123,018
(70,582)
(158)
229
2,877
(23,513)
17,507
83
(286)
355,948
64,564
354
21,390
4,557
(61,304)
78,421
(94)
557
3,061
9,011
(977)
(480)
(414)
Net Cash Provided by (Used in) Operating Activities
215,726
165,212
Cash Flows from Investing Activities:
Additions to property and equipment
Acquisition of oil and gas properties
Proceeds from the sale of property and equipment
Payments on property sale obligations
Net Cash Provided by (Used in) Investing Activities
Cash Flows from Financing Activities:
Payments of long-term debt
Proceeds from bank borrowings
Payments of bank borrowings
Net proceeds from issuances of common stock
Purchase of treasury shares
Payments of debt issuance costs
Net Cash Provided by (Used in) Financing Activities
Net Increase (Decrease) in Cash and Cash Equivalents and Restricted Cash
Cash, Cash Equivalents and Restricted Cash at Beginning of Year
Cash, Cash Equivalents and Restricted Cash at End of Year
Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest
Changes in capital accounts payable and capital accruals
Non-cash equity consideration for acquisitions
See accompanying Notes to Consolidated Financial Statements.
$
$
$
$
(133,638)
(51,734)
—
(1,084)
(114,738)
(4,544)
4,777
(826)
(186,456)
(115,331)
(50,000)
335,000
(338,000)
26,956
(612)
(3,611)
(30,267)
(997)
2,118
1,121 $
27,221 $
(4,033) $
(83,522) $
—
107,000
(156,000)
—
(90)
(31)
(49,121)
760
1,358
2,118
28,929
(19,365)
—
Notes to Consolidated Financial Statements
SilverBow Resources, Inc. and Subsidiary
1. Summary of Significant Accounting Policies
Principles of Consolidation. The accompanying consolidated financial statements include the accounts of SilverBow
Resources and its wholly owned subsidiary, SilverBow Resources Operating LLC, (collectively, the “Company”, “SilverBow”,
“we”, “our” or “us”) which are engaged in the exploration, development, acquisition, and operation of oil and gas properties,
with a focus on oil and natural gas reserves in the Eagle Ford and Austin Chalk trend in Texas. Our undivided interests in oil
and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of the
assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying consolidated
financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying consolidated
financial statements. We operate in and report our financial results and disclosures as one segment, which is the exploration,
development and production of oil and natural gas.
COVID-19. The spread of COVID-19 and its impact on the global supply of and demand for crude oil caused volatility in
the market price for crude oil during 2020. The spot price of West Texas Intermediate (“WTI”) crude oil declined over 50% in
March and April of 2020 before gradually improving through the rest of 2020 and 2021. The spot price of Brent and WTI crude
oil closed at approximately $64 and $59 per barrel, respectively, on March 31, 2021, and thereafter increased to approximately
$77 and $75 per barrel, respectively, on December 31, 2021.
In response to these market conditions, including the COVID-19 pandemic and the volatility in oil prices during 2020, the
Company released its sole drilling rig in April 2020 and deferred the completion and placement on production of eight wells
until the second half of 2020. In the third quarter of 2020, the Company restarted completions activity and returned to sales all
previously curtailed volumes as of December 31, 2020.
Except as described above regarding the curtailment of production in 2020, SilverBow has not experienced any material
interruption to its ordinary course business processes as a result of the COVID-19 pandemic and the volatility in oil and gas
prices. The Company will continue to monitor the COVID-19 situation and follow the advice of government and health leaders.
Subsequent Events. We have evaluated subsequent events requiring potential accrual or disclosure in our condensed
consolidated financial statements.
Through February 25, 2022, the Company entered into additional derivative contracts. The following tables summarize the
weighted-average prices as well as future production volumes for our future derivative contracts entered into after
December 31, 2021:
Oil Derivative Swaps
(New York Mercantile Exchange (“NYMEX”) WTI Settlements)
Swap Contracts
2022 Contracts
4Q22
2023 Contracts
1Q23
2Q23
3Q23
4Q23
Total
Volumes
(Bbls)
Weighted
Average
Price
23,000 $
80.82
45,000 $
45,500 $
46,000 $
94,300 $
78.60
76.90
75.45
73.52
56
57
Natural Gas Derivative Contracts
(NYMEX Henry Hub Settlements)
Total
Volumes
(MMBtu)
Weighted
Average
Price
Weighted-
Average
Collar Floor
Price
Weighted-
Average
Collar Call
Price
Swap Contracts
2Q22
3Q22
Collar Contracts
2022 Contracts
1Q22
3Q22
4Q22
2023 Contracts
1Q23
4Q23
2024 Contracts
1Q24
NGL Swaps (Mont Belvieu)
2022 Contracts
1Q22
2Q22
3Q22
4Q22
Oil Basis Derivative Swaps
(Argus Cushing (WTI) and Magellan East Houston)
Calendar Monthly Roll Differential Swaps
2022 Contracts
2Q22
600,000 $
310,000 $
4.50
4.57
310,000
920,000
920,000
900,000
4,462,000
910,000
$
$
$
$
$
$
5.00 $
4.40 $
4.40 $
4.40 $
3.25 $
7.40
5.02
5.43
5.84
3.92
3.25 $
5.19
Total Volumes
(Bbls)
Weighted-
Average Price
15,500 $
45,500 $
46,000 $
46,000 $
35.40
35.40
35.40
35.40
Total Volumes
(Bbls)
Weighted
Average Price
45,500 $
2.63
Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in
the United States (“GAAP”) requires us to make estimates and assumptions that affect the reported amounts of certain assets
and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and
assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such
estimates. Significant estimates and assumptions underlying these financial statements include:
•
•
•
•
•
•
•
•
•
•
the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas
properties, the related present value of estimated future net cash flow therefrom, and the Ceiling Test impairment
calculation,
estimates related to the collectability of accounts receivable and the credit worthiness of our customers,
estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf,
estimates of future costs to develop and produce reserves,
accruals related to oil and gas sales, capital expenditures and lease operating expenses (“LOE”),
estimates in the calculation of share-based compensation expense,
estimates of our ownership in properties prior to final division of interest determination,
the estimated future cost and timing of asset retirement obligations,
estimates made in our income tax calculations, including the valuation of our deferred tax assets,
estimates in the calculation of the fair value of commodity derivative assets and liabilities,
•
•
•
•
estimates in the assessment of current litigation claims against the Company,
estimates used in the assessment of business combinations and asset purchases,
estimates in amounts due with respect to open state regulatory audits, and
estimates on future lease obligations.
While we are not currently aware of any material revisions to any of our estimates, there may be future revisions to our
estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint
venture audits, reallocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas
industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be
recorded in the period during which the adjustments are known.
We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of
business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated.
Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment
costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and
acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a
property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs
incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own
account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the
years ended December 31, 2021 and 2020, such internal costs when capitalized totaled $4.8 million and $3.5 million,
respectively. There was no capitalized interest on our unproved properties for both the years ended December 31, 2021 and
2020.
The “Property and Equipment” balances on the accompanying consolidated balance sheets are summarized for presentation
purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands):
Property and Equipment
Proved oil and gas properties
Unproved oil and gas properties
Furniture, fixtures, and other equipment
Less – Accumulated depreciation, depletion, amortization & impairment
Property and Equipment, Net
December 31,
2021
December 31,
2020
$
1,588,978 $
1,310,008
17,090
5,885
28,090
5,275
(869,985)
(801,279)
$
741,968 $
542,094
No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions
involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would
significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost
center. Internal costs associated with selling properties are expensed as incurred.
We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using
the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil
and gas properties, including future development costs, gas processing facilities, and both capitalized asset retirement
obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved
properties, by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural
gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which
excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a
property-by-property basis based on current economic conditions. The period over which we will amortize these properties is
dependent on our production from these properties in future years. Furniture, fixtures, and other equipment are recorded at cost
and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between
two and 20 years. Repairs and maintenance are charged to expense as incurred.
Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved oil and gas
properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are
58
59
capitalized in “Unproved oil and gas properties” and evaluated as part of the total capitalized costs associated with a prospect.
The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine
whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling
results, lease expiration dates, current oil and gas industry conditions, economic conditions, capital availability, and available
geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.
The Company evaluates each acquisition of oil and gas properties to determine whether each should be accounted for as an
acquisition of assets or business in accordance with Accounting Standards Update No. 2017-01: Business Combinations (Topic
805) Clarifying the Definition of a Business (“ASU 2017-01”). If substantially all of the fair value of the gross assets acquired
is concentrated in a single identifiable asset or group of similar identifiable assets, the set of transferred assets and activities are
not a business combination.
A business combination may result in the recognition of a bargain purchase gain or goodwill based on the measurement of
the fair value of the assets and liabilities acquired at the acquisition date as compared to the fair value of consideration
transferred, adjusted for purchase price adjustments. The initial accounting for acquisitions may not be complete and
adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more
detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the
acquisition dates. Asset acquisitions are recorded at the cost of acquiring the property. The results of operations of the oil and
gas properties acquired in the Company’s acquisitions have been included in the consolidated financial statements since the
closing dates of the respective acquisitions. See Note 9 for further discussion on recent acquisitions.
Full-Cost Ceiling Test. At the end of the reporting period, the unamortized cost of oil and natural gas properties (including
natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income
taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from
recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the
preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials,
discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling
Test”).
The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There
are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production,
timing and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the
estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and
natural gas that are ultimately recovered. There was no ceiling test write-down for the year ended December 31, 2021. Due to
the effects of pricing and timing of projects we reported a non-cash impairment write-down, on a pre-tax basis, of $355.9
million for the year ended December 31, 2020.
If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant
declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flow from
proved oil and natural gas reserves) or if oil or natural gas prices decline, it is possible that non-cash write-downs of our oil and
natural gas properties will occur again in the future. We cannot control and cannot predict what future prices for oil and natural
gas will be; therefore we cannot estimate the amount of any potential future non-cash write-down of our oil and natural gas
properties due to decreases in oil or natural gas prices. However, it is reasonably possible that we will record additional Ceiling
Test write-downs in future periods.
Revenue Recognition. Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas
liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is
transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly
basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are
satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to
a designated delivery point. Natural gas revenues are recognized based on the actual volume of natural gas sold to the
purchasers.
The following table provides information regarding our oil and gas sales, by product, reported on the Consolidated
Statements of Operations for years ended December 31, 2021 and 2020 (in thousands):
Oil, natural gas and NGLs sales:
Oil
Natural gas
NGLs
Total
Year Ended
December 31, 2021
Year Ended
December 31, 2020
$
$
98,607 $
267,687
40,906
407,200 $
57,651
105,234
14,500
177,386
Accounts Receivable, Net. We assess the collectability of accounts receivable, and based on our judgment, we accrue a
reserve when we believe a receivable may not be collected. At both December 31, 2021 and 2020, we had an allowance for
doubtful accounts of less than $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts
receivable, net” balance on the accompanying consolidated balance sheets.
At December 31, 2021, our “Accounts receivable, net” balance included $45.3 million for oil and gas sales, $1.9 million
due from joint interest owners, $1.0 million for severance tax credit receivables and $1.5 million for other receivables. At
December 31, 2020, our “Accounts receivable, net” balance included $18.8 million for oil and gas sales, $4.0 million for joint
interest owners, $2.4 million for severance tax credit receivables and $0.7 million for other receivables.
Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our
wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and
administrative, net”, on the accompanying consolidated statements of operations. The amount of supervision fees charged for
each of the years ended December 31, 2021 and 2020 did not exceed our actual costs incurred. The total amount of supervision
fees charged to the wells we operated was $5.1 million and $4.4 million for the years ended December 31, 2021 and 2020,
respectively.
Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial
statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. Tax positions are evaluated for
recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest
amount of tax benefit with a greater than 50% likelihood of being realized upon ultimate settlement with a taxing authority that
has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in
income tax expense. At December 31, 2021, we did not have any accrued liability for uncertain tax positions and do not
anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.
In March and April 2020, the COVID-19 pandemic caused volatility in the market price for crude oil due to the disruption
of global supply and demand. In response to these market conditions and given the decline in oil prices and economic outlook
for our Company, management determined that it was not more likely than not that the Company would realize future cash
benefits from its remaining federal carryover items and other deferred tax assets and, accordingly, recorded a full valuation
allowance in the second quarter of 2020 to offset its net deferred tax assets in excess of deferred tax liabilities. Our income tax
provision of $20.9 million for the year ended December 31, 2020 is inclusive of a state income tax benefit of $1.8 million. The
Company maintains a full valuation allowance against its net federal deferred tax assets in excess of deferred tax liabilities as of
December 31, 2021. We recorded an income tax provision of $6.4 million which was primarily attributable to deferred federal
income tax expense for the year ended December 31, 2021.
On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security Act (the
“CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment
of employer-side Social Security payments, net operating loss carryback periods, alternative minimum tax credit refunds and
modifications to the net interest deduction limitation. The Company has examined the impact of the CARES Act and has
concluded the CARES Act will not have a material effect on its financial condition, results of operation, or liquidity.
60
61
Accounts Payable and Accrued Liabilities. The “Accounts payable and accrued liabilities” balances on the
accompanying consolidated balance sheets are summarized below (in thousands):
Trade accounts payable
Accrued operating expenses
Accrued compensation costs
Asset retirement obligations – current portion
Accrued non-income based taxes
Accrued corporate and legal fees
Other payables(1)
Total accounts payable and accrued liabilities
December 31,
2021
December 31,
2020
$
9,688 $
4,192
7,029
524
3,314
1,972
8,315
$
35,034 $
15,930
2,491
3,771
441
1,819
150
2,389
26,991
(1) Included in Other Payables is $6.4 million and $0.8 million in payables for settled derivatives for the years ended December 31, 2021 and 2020,
respectively.
Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to
be cash equivalents. These amounts do not include cash balances that are contractually restricted.
Credit Risk Due to Certain Concentrations. We extend credit, primarily in the form of uncollateralized oil and gas sales
and joint interest owners' receivables, to various companies in the oil and gas industry, which results in a concentration of credit
risk. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may
accordingly impact our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the
size, reputation, and nature of the companies to which we extend credit. From certain customers we also obtain letters of credit
or parent company guarantees, if applicable, to reduce risk of loss.
For the years ended December 31, 2021 and 2020, parties that accounted for 10% or more of our total oil and gas receipts
were as follows:
Purchasers greater than 10%
Kinder Morgan
Plains Marketing
Twin Eagle
Trafigura US
Shell Trading
*Oil and gas receipts less than 10%
Year Ended
December 31,
2021
Year Ended
December 31,
2020
26 %
10 %
15 %
16 %
12 %
19 %
17 %
17 %
13 %
*
Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock held, at cost” on
the accompanying consolidated balance sheets. For the years ended December 31, 2021 and 2020, we purchased 74,586 and
28,731 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares.
New Accounting Pronouncements. In March 2020, the FASB issued ASU No. 2020-03. ASU 2020-03 improves and
clarifies various financial instruments topics, including the current expected credit loss standard (“CECL”). ASU 2020-03
includes seven different issues that describe the areas of improvement and the related amendments to GAAP, intended to make
the standards easier to understand and apply by eliminating inconsistencies and providing clarifications. This guidance is
effective beginning on January 1, 2023 for smaller reporting companies. We are still assessing the requirements to determine
the impact of this guidance on our consolidated financial statements.
In August 2020, the FASB issued ASU No. 2020-06. This ASU simplifies the accounting for certain financial instruments
with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. For
convertible instruments with conversion features that are not accounted for as derivatives under ASC 815 or do not result in
substantial premiums accounted for as paid-in capital, the convertible instrument's embedded conversion features are no longer
separated from the host contract. Consequently, and as long as no other feature requires bifurcation and recognition as a
derivative, the convertible instrument is accounted for as a single liability measured at its amortized cost. This ASU also
amends the impact of convertible instruments on the calculation of diluted earnings per share (EPS) and adds several new
disclosure requirements. The ASU is effective for fiscal years beginning after December 15, 2021. The ASU can be adopted on
either a fully retrospective or modified retrospective basis. The adoption of this guidance is not expected to have a material
impact on the Company’s consolidated financial statements or disclosures.
In May 2021, the FASB issued ASU 2021-04. This guidance provides clarification and reduces diversity in an issuer’s
accounting for modifications or exchanges of freestanding equity-classified written call options (such as warrants) that remain
equity classified after modification or exchange. An issuer measures the effect of a modification or exchange as the difference
between the fair value of the modified or exchanged warrant and the fair value of that warrant immediately before modification
or exchange. The ASU introduces a recognition model that comprises four categories of transactions and the corresponding
accounting treatment for each category (equity issuance, debt origination, debt modification, and modifications unrelated to
equity issuance and debt origination or modification). This guidance is effective for all entities for fiscal years beginning after
December 15, 2021, including interim periods within those fiscal years. The adoption of this guidance is not expected to have a
material impact on the Company’s consolidated financial statements or disclosures.
ATM Program. On August 13, 2021, the Company entered into an equity distribution agreement pursuant to which the
Company may sell, from time to time in the open market, shares of the Company’s common stock, having aggregate proceeds
of up to $40.0 million (the “ATM Program”). The Company intends to use the net proceeds from any sales through the ATM
Program for general corporate purposes, including, but not limited to, financing of capital expenditures, repayment or
refinancing of outstanding debt, financing acquisitions or investments, financing other business opportunities, and general
working capital purposes. During the year ended December 31, 2021 (from August 13, 2021 through December 31, 2021), the
Company sold 1,222,209 shares of common stock for net proceeds of $27.0 million after deducting sales agents' commissions
and other related expenses.
2. Earnings Per Share
Basic earnings per share (“Basic EPS”) has been computed using the weighted average number of common shares
outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise
of stock options and restricted stock grants using the treasury stock method. Diluted EPS also assumes conversion of
performance-based restricted stock units to common shares based on the number of shares (if any) that would be issuable,
according to predetermined performance and market goals, if the end of the reporting period was the end of the performance
period.
The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS
for the periods indicated below (in thousands, except per share amounts):
Year Ended December 31, 2021
Year Ended December 31, 2020
Net Income
(Loss)
Shares
Per Share
Amount
Net Income
(Loss)
Shares
Per Share
Amount
$
86,759
13,118 $
6.61 $
(309,382)
11,902 $
(25.99)
285
117
—
—
Basic EPS:
Net Income (Loss) and
Share Amounts
Dilutive Securities:
Restricted Stock Unit
Awards
Performance Based Stock
Unit Awards
Diluted EPS:
Net Income (Loss) and
Assumed Share Conversions $
86,759
13,520 $
6.42 $
(309,382)
11,902 $
(25.99)
Approximately 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for both
the years ended December 31, 2021 and 2020, because these stock options were antidilutive.
There were no antidilutive shares of restricted stock units for the year ended December 31, 2021. Approximately 0.2
million shares of restricted stock units that could be converted to common shares were not included in the computation of
Diluted EPS for the year ended December 31, 2020 because they were antidilutive.
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63
There were no antidilutive shares of performance-based restricted stock units for the year ended December 31, 2021.
Approximately 0.1 million shares of performance-based restricted stock units were not included in the computation of Diluted
EPS for the year ended December 31, 2020 because they were antidilutive.
3. Provision (Benefit) for Income Taxes
Income (Loss) before taxes is as follows (in thousands):
Income (Loss) Before Income Taxes
Year Ended
December 31, 2021
Year Ended
December 31, 2020
$
93,157 $
(288,471)
The following is an analysis of the consolidated income tax provision (benefit) (in thousands):
Current
Deferred
Total
Year Ended
December 31, 2021
Year Ended
December 31, 2020
$
$
186 $
6,212
6,398 $
(480)
21,391
20,911
Reconciliations of income taxes computed using the U.S. Federal statutory rate of (21%) to the effective income tax rate
are as follows:
Federal Statutory Rate
State tax provisions (benefits), net of federal benefits
Executive compensation limitation
Other, net
Valuation allowance adjustments
Effective rate
Year Ended
December 31, 2021
Year Ended
December 31, 2020
21.0 %
1.0 %
0.6 %
0.6 %
(16.2) %
6.9 %
21.0 %
0.6 %
— %
(0.2) %
(28.6) %
(7.2) %
The tax effects of temporary differences representing the net deferred tax asset (liability) at December 31, 2021 and 2020
were as follows (in thousands):
Deferred tax assets:
December 31, 2021 December 31, 2020
Federal net operating loss (“NOL”) carryovers
$
97,142 $
Other carryover items
Asset retirement obligations
Share-based compensation
Lease liability
Derivative contracts
Other
Valuation allowance
Total deferred tax assets
Deferred tax liabilities:
Oil and gas exploration and development costs
Derivative contracts
Leased assets
Other
Total deferred tax liabilities
Net deferred tax asset (liabilities)
State net deferred tax liabilities
Federal net deferred tax liabilities
Net deferred tax asset (liabilities)
642
1,306
579
3,425
11,451
2,111
(67,578)
49,078 $
(52,219) $
—
(3,374)
(1)
(55,594)
(6,516) $
(1,016) $
(5,500)
(6,516) $
$
$
$
$
$
93,293
610
1,074
959
929
—
1,029
(82,618)
15,276
(13,008)
(1,653)
(917)
(1)
(15,579)
(303)
(303)
—
(303)
The Company’s valuation allowance balance was $67.6 million and $82.6 million at December 31, 2021 and 2020,
respectively. The Company recorded a net deferred tax liability for state income tax purposes at December 31, 2021 and 2020.
The Company’s NOL carryforward asset is attributable to Federal tax losses of $114.6 million generated from 2013
through 2015, $159.6 million generated in 2017 and $188.3 million generated from 2018 through 2021. The losses generated
between 2013 and 2015 are subject to an annual utilization limit under Sec. 382. These losses will expire between 2033 and
2035 if not utilized. The 2017 loss will expire in 2037 if not utilized. The losses generated from 2018 through 2021 will not
expire under the current tax code, but their usage will be limited to 80% of taxable income.
Our U.S. federal and most state income tax returns from 2018 forward are subject to examination. For years prior to 2018
our U.S. federal returns are subject to examination to the extent of our net operating loss (NOL) carryforwards. Our Texas tax
returns from 2017 forward are subject to examination. There are no material unresolved items related to periods previously
audited by the taxing authorities.
4. Long-Term Debt
The Company's long-term debt consisted of the following (in thousands):
Credit Facility Borrowings (1)
Second Lien Notes due 2026
Unamortized discount on Second Lien Notes
Unamortized debt issuance cost on Second Lien Notes
Total Long-Term Debt
December 31, 2021 December 31, 2020
230,000
$
200,000
227,000 $
150,000
377,000
(1,061)
(3,114)
372,825 $
430,000
(1,295)
(3,800)
424,905
$
(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our consolidated balance sheet. As of
December 31, 2021 and 2020, we had $3.6 million and $1.4 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.
64
65
Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $227.0 million and
$230.0 million as of December 31, 2021 and 2020, respectively. The Company is a party to a First Amended and Restated
Senior Secured Revolving Credit Agreement with JPMorgan Chase Bank, National Association, as administrative agent, and
certain lenders party thereto, as amended (such agreement, the “Credit Agreement” and the borrowing facility provided thereby,
the “Credit Facility”). In conjunction with its regularly scheduled semi-annual redetermination, the Company entered into the
Eighth Amendment to the Credit Facility, effective November 12, 2021 (the “Eighth Amendment”), which increased the
borrowing base under the Credit Facility to $460.0 million (from $300.0 million).
The Credit Facility matures April 19, 2024 and provides for a maximum credit amount of $1.0 billion and a current
borrowing base of $460.0 million as of December 31, 2021. The borrowing base is regularly redetermined on or about May and
November of each calendar year and is subject to additional adjustments from time to time, including for asset sales,
elimination or reduction of hedge positions and incurrence of other debt. Additionally, the Company and the administrative
agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of
the borrowing base is determined by the lenders, in their discretion, in accordance with their oil and gas lending criteria at the
time of the relevant redetermination. The Company may also request the issuance of letters of credit under the Credit
Agreement in an aggregate amount up to $25 million, which reduces the amount of available borrowings under the borrowing
base in the amount of such issued and outstanding letters of credit. There were no outstanding letters of credit as of December
31, 2021 and 2020. Maintaining or increasing our borrowing base under our Credit Facility is dependent on many factors,
including commodity prices, our hedge positions, changes in our lenders' lending criteria and our ability to raise capital to drill
wells to replace produced reserves.
Interest under the Credit Facility accrues at the Company’s option either at an Alternative Base Rate plus the applicable
margin (“ABR Loans”), the Adjusted Term Secured Overnight Financing Rate (“SOFR”) plus the applicable margin (“Term
Benchmark Loans”) or Adjusted Daily Simple SOFR plus the applicable margin (“RFR Loans”). Effective November 12, 2021,
the applicable margin ranged from 2.25% to 3.25% for ABR Loans and 3.25% to 4.25% for Term Benchmark Loans and RFR
Loans. The Alternate Base Rate and SOFR are defined, and the applicable margins are set forth, in the Credit Agreement.
Undrawn amounts under the Credit Facility are subject to a 0.50% commitment fee. To the extent that a payment default exists
and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.00% per annum above the rate and
margin otherwise applicable thereto.
The obligations under the Credit Agreement are secured, subject to certain exceptions, by a first priority lien on
substantially all assets of the Company and its subsidiary, including a first priority lien on properties attributed with at least
90% of estimated proved reserves of the Company and its subsidiary.
The Credit Agreement contains the following financial covenants:
•
•
a ratio of total debt to earnings before interest, tax, depreciation and amortization (“EBITDA”), as defined in the Credit
Agreement, for the most recently completed four fiscal quarters, not to exceed (i) 3.25 to 1.0 as of the last day of each
fiscal quarter for any fiscal quarter ending on or before December 31, 2021 and (ii) 3.0 to 1.0 as of the last day of each
fiscal quarter, commencing with fiscal quarter ending March 31, 2022, and for any fiscal quarter thereafter; and
a current ratio, as defined in the Credit Agreement, which includes in the numerator available borrowings undrawn
under the borrowing base, of not less than 1.0 to 1.0 as of the last day of each fiscal quarter.
As of December 31, 2021, the Company was in compliance with all financial covenants under the Credit Agreement.
Additionally, the Credit Agreement contains certain representations, warranties and covenants, including but not limited to,
limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments,
limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying
organizational documents and material contracts. The Credit Agreement contains customary events of default. If an event of
default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately
due and payable.
Total interest expense on the Credit Facility, which includes commitment fees and amortization of debt issuance costs, was
$11.3 million and $12.6 million for the years ended December 31, 2021 and 2020, respectively. The amount of commitment fee
amortization included in interest expense, net was $0.5 million and $0.4 million for the years ended December 31, 2021 and
2020, respectively.
Senior Secured Second Lien Notes. On December 15, 2017, the Company entered into a Note Purchase Agreement for
Senior Secured Second Lien Notes (as amended, the “Note Purchase Agreement”, such second lien facility, the “Second Lien”
and such notes, the “Second Lien Notes”) among the Company as issuer, U.S. Bank National Association as agent and
collateral agent and certain holders that are a party thereto, and issued notes in an initial principal amount of $200.0 million,
with a $2.0 million discount, for net proceeds of $198.0 million.
Effective November 12, 2021, the Company entered into the Second Amendment to the Note Purchase Agreement, which
extended the maturity date from December 15, 2024 to December 15, 2026 subject to paying down the principal amount of the
Second Lien from $200.0 million to $150.0 million. The Company made the $50 million redemption of the Second Lien Notes
on November 29, 2021. The Company accounted for this paydown as a debt modification and incurred approximately
$0.1 million in third party fees in connection with the amendment. The unamortized debt issuance cost and discount on the
Second Lien Notes will be amortized through the new maturity date of December 15, 2026.
Interest on the Second Lien is payable quarterly and accrues at LIBOR plus 7.5%; provided that if LIBOR ceases to be
available, the Second Lien provides for a mechanism to use Alternate Base Rate plus 6.5% as the applicable interest rate. The
definitions of LIBOR and Alternate Base Rate are set forth in the Note Purchase Agreement. To the extent that a payment,
insolvency or, at the holders’ election, another default exists and is continuing, all amounts outstanding under the Second Lien
will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. Additionally, to the extent the
Company were to default on the Second Lien, this would potentially trigger a cross-default under its Credit Facility.
The Company has the right, to the extent permitted under the Credit Facility and subject to the terms and conditions of the
Second Lien, to optionally prepay the notes, subject to a repayment fee of 1.0% of the principal amount of the Second Lien
being prepaid through December 15, 2022; and thereafter, no premium. Additionally, the Second Lien contains customary
mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and incurrences of certain
debt, subject to, in certain circumstances, reinvestment periods. Management believes the probability of mandatory prepayment
due to default is remote.
The obligations under the Second Lien are secured, subject to certain exceptions and other permitted liens (including the
liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit
Facility, and mortgage lien on substantially all assets of the Company and its subsidiary, including a mortgage lien on oil and
gas properties attributed with at least 90% of estimated PV-9 (defined below), of proved reserves of the Company and its
subsidiary and 90% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is
determined using commodity price assumptions by the administrative agent of the Credit Facility. PV-9 value is the estimated
future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount
rate of 9%.
The Second Lien contains an Asset Coverage Ratio, which is only tested (i) as a condition to issuance of additional notes
and (ii) in connection with certain asset sales in order to determine whether the proceeds of such asset sale must be applied as a
prepayment of the notes and includes in the numerator the PV-10 (defined below), based on forward strip pricing, plus the swap
mark-to-market value of the commodity derivative contracts of the Company and its restricted subsidiary and in the
denominator the total net indebtedness of the Company and its restricted subsidiary, of not less than 1.25 to 1.0 as of each date
of determination (the “Asset Coverage Ratio”). PV-10 Value is the estimated future net revenues to be generated from the
production of proved reserves discounted to present value using an annual discount rate of 10%.
The Second Lien also contains a financial covenant measuring the ratio of total net debt to EBITDA, as defined in the Note
Purchase Agreement, for the most recently completed four fiscal quarters, not to exceed (i) 3.5 to 1.0 as of the last day of each
fiscal quarter for any fiscal quarter ending on or before December 31, 2021, (ii) and 3.25 to 1.0 as of the last day of each fiscal
quarter, commencing with fiscal quarter ending March 31, 2022, and for any fiscal quarter thereafter. As of December 31, 2021,
the Company was in compliance with all financial covenants under the Second Lien.
The Second Lien contains certain customary representations, warranties and covenants, including but not limited to,
limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments,
limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying
organizational documents and material contracts. The Second Lien contains customary events of default. If an event of default
occurs and is continuing, the lenders may declare all amounts outstanding under the Second Lien to be immediately due and
payable.
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67
As of December 31, 2021, net amounts recorded for the Second Lien Notes were $145.8 million, net of unamortized debt
discount and debt issuance costs. Interest expense on the Second Lien totaled $17.8 million and $18.6 million for the years
ended December 31, 2021 and 2020, respectively.
Debt Issuance Costs. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our
line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are
any outstanding borrowings.
5. Price-Risk Management Activities
Derivatives are recorded on the balance sheet at fair value with changes in fair value recognized in earnings. The changes
in the fair value of our derivatives are recognized in “Gain (loss) on commodity derivatives, net” on the accompanying
consolidated statements of operations. We have a price-risk management policy to use derivative instruments to protect against
declines in oil and natural gas prices, primarily through the purchase of commodity price swaps and collars as well as basis
swaps.
During the years ended December 31, 2021 and 2020, the Company recorded losses of $123.0 million and gains of $61.3
million, respectively, relating to our derivative activities. The Company made net cash payments of $70.6 million and received
net cash payments of $78.4 million for settled derivative contracts during the years ended December 31, 2021 and 2020,
respectively. Included in our collected cash payments during the year ended December 31, 2020 was $38.3 million for
monetized derivative contracts received in the first quarter of 2020.
At December 31, 2021 and 2020, we had $0.9 million and $0.8 million, respectively, in receivables for settled derivatives
which were included on the accompanying consolidated balance sheets in “Accounts receivable, net” and were subsequently
collected in January 2022 and 2021, respectively. At December 31, 2021 and 2020, we also had $6.4 million and $0.8 million,
respectively, in payables for settled derivatives which were included on the accompanying consolidated balance sheets in
“Accounts payable and accrued liabilities” and were subsequently paid in January 2022 and 2021, respectively.
The fair values of our swap contracts are computed using observable market data whereas our collar contracts are valued
using a Black-Scholes pricing model. At December 31, 2021 there was $2.8 million and $0.2 million in current unsettled
derivative assets and long-term unsettled derivative assets, respectively, and $47.5 million and $8.6 million in current unsettled
derivative liabilities and long-term unsettled derivative liabilities, respectively. At December 31, 2020, the Company had $4.8
million and $0.3 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $8.2
million and $2.9 million in current unsettled derivative liabilities and long-term unsettled derivative liabilities, respectively.
The Company uses an International Swap and Derivatives Association master agreement for our derivative contracts. This
is an industry-standardized contract containing the general conditions of our derivative transactions including provisions
relating to netting derivative settlement payments under certain circumstances (such as default). For reporting purposes, the
Company has elected to not offset the asset and liability fair value amounts of its derivatives on the accompanying consolidated
balance sheets. Under the right of set-off, there was an $53.0 million net fair value liability at December 31, 2021 and $6.0
million net fair value liability at December 31, 2020. For further discussion related to the fair value of the Company's
derivatives, refer to Note 10 of these Notes to Consolidated Financial Statements.
The following tables summarize the weighted average prices as well as future production volumes for our future derivative
contracts in place as of December 31, 2021.
Oil Derivative Swaps
(New York Mercantile Exchange (“NYMEX”) WTI Settlements)
Total
Volumes
(Bbls)
Weighted
Average
Price
Weighted
Average
Collar
Floor Price
Weighted
Average
Collar Call
Price
Swap Contracts
2022 Contracts
1Q22
2Q22
3Q22
4Q22
2023 Contracts
1Q23
2Q23
3Q23
Collar Contracts
2022 Contracts
1Q22
2Q22
3Q22
4Q22
2023 Contracts
1Q23
2Q23
3Q23
4Q23
Natural Gas Derivative Swaps
(NYMEX Henry Hub Settlements)
Swap Contracts
2022 Contracts
1Q22
2Q22
3Q22
4Q22
Collar Contracts
2022 Contracts
1Q22
2Q22
3Q22
4Q22
2023 Contracts
1Q23
2Q23
3Q23
223,455 $
136,500 $
246,100 $
184,000 $
82,175 $
575 $
53,980 $
49.32
56.66
49.63
54.84
55.75
68.40
66.55
85,500
161,350
46,000
46,000
45,000
111,475
46,000
46,000
$
$
$
$
$
$
$
$
57.37 $
48.21 $
70.00 $
68.00 $
65.00 $
59.27 $
63.00 $
62.00 $
63.55
55.16
75.40
73.60
72.80
66.32
69.10
67.55
Total
Volumes
(MMBtu)
Weighted
Average
Price
Weighted
Average
Collar
Floor Price
Weighted
Average
Collar Call
Price
232,500 $
3,795,000 $
4,142,100 $
2,760,000 $
4.00
2.99
3.02
3.14
9,645,000
6,156,500
6,739,000
7,765,076
8,347,000
4,898,500
4,600,000
$
$
$
$
$
$
$
3.06 $
2.29 $
2.60 $
2.69 $
2.89 $
2.57 $
2.88 $
3.79
2.74
2.98
3.20
3.52
2.97
3.28
68
69
Natural Gas Basis Derivative Swaps
(East Texas Houston Ship Channel vs. NYMEX Settlements)
Total Volumes
(MMBtu)
Weighted
Average Price
2022 Contracts
1Q22
2Q22
3Q22
4Q22
Oil Basis Derivative Swaps
(Argus Cushing (WTI) and Magellan East Houston)
Calendar Monthly Roll Differential Swaps
2022 Contracts
1Q22
2Q22
3Q22
4Q22
NGL Swaps (Mont Belvieu)
2022 Contracts
1Q22
2Q22
3Q22
4Q22
6. Commitments and Contingencies
8,100,000 $
3,640,000 $
3,680,000 $
3,680,000 $
0.093
(0.051)
(0.043)
(0.048)
Total Volumes
(Bbls)
Weighted
Average Price
261,000 $
263,900 $
266,800 $
266,800 $
0.19
0.19
0.19
0.19
Total Volumes
(Bbls)
Weighted-
Average Price
180,000 $
136,500 $
138,000 $
138,000 $
29.13
28.85
28.34
28.27
We have gas transportation and processing minimum obligations amounting to $1.8 million for 2022, $2.7 million for
2023, $1.7 million for 2024, $1.2 million for 2025 and $7.4 million in the aggregate. These gas transportation and processing
minimum obligations represent gross future minimum transportation charges we are obligated to pay as of December 31, 2021.
However, our financial statements will reflect our proportionate share of the charges based on our working interest and net
revenue interest, which will vary from property to property. Actual transportation under these contracts may exceed the
minimum commitments previously stated. The Company incurred transportation expense related to these contracts of
$7.5 million and $4.4 million for the years ended December 31, 2021 and 2020, respectively.
In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as
operator of oil and natural gas wells. In management's opinion, the outcome of any such currently pending legal actions will not
have a material adverse effect on our financial position or results of operations.
7. Share-Based Compensation
Share-Based Compensation Plans
In 2016, the Company adopted the 2016 Equity Incentive Plan (as amended from time to time, the “2016 Plan”). The
Company also adopted the Inducement Plan (as amended from time to time, the “Inducement Plan,” and, together with the 2016
Plan, the “Plans”) on December 15, 2016.
The Company computes a deferred tax benefit for restricted stock awards (“RSUs”), performance-based stock units
(“PSUs”) and stock options designed to generate future tax deductions by applying its effective tax rate to the expense recorded.
For restricted stock units, the Company's actual tax deduction is based on the value of the units at the time of vesting.
The expense for awards issued to both employees and non-employees, which was recorded in “General and administrative,
net” in the accompanying consolidated statements of operations was $4.6 million for both the years ended December 31, 2021
and 2020. Capitalized share-based compensation was $0.2 million and for both the years ended December 31, 2021 and 2020.
We view stock option awards and restricted stock unit awards with graded vesting as single awards with an expected life
equal to the average expected life of component awards, and we amortize the awards on a straight-line basis over the life of the
awards. The Company accounts for forfeitures in compensation cost when they occur.
Our shares available for future grant under the Plans were 349,265 at December 31, 2021.
Stock Option Awards
The compensation cost related to these awards is based on the grant date fair value and is expensed over the vesting period
(generally one to five years). We use the Black-Scholes-Merton option pricing model to estimate the fair value of stock option
awards.
At December 31, 2021, we had $0.1 million in unrecognized compensation cost related to stock option awards. The
following table represents stock option award activity for the year ended December 31, 2021:
Options outstanding, beginning of period
Options forfeited
Options expired
Options outstanding, end of period
Options exercisable, end of period
Shares
Wtd. Avg.
Exer. Price
27.73
16.96
23.25
28.12
28.53
303,705 $
(3,896) $
(23,800) $
276,009 $
226,950 $
Our outstanding stock option awards at December 31, 2021 had no measurable aggregate intrinsic value. At December 31,
2021 the weighted-average remaining contract life of stock option awards outstanding was 4.1 years and exercisable was 3.8
years. The stock option awards exercisable as of December 31, 2021 had no intrinsic value.
Restricted Stock Units
The Plans allow for the issuance of restricted stock unit awards that generally may not be sold or otherwise transferred until
certain restrictions have lapsed. The compensation cost related to these awards is based on the grant date fair value and is
typically expensed over the requisite service period (generally one to five years).
As of December 31, 2021, we had unrecognized compensation expense of $0.7 million related to our restricted stock units
which is expected to be recognized over a weighted-average period of 0.7 years.
The following table provides information regarding restricted stock unit activity for the year ended December 31, 2021:
Restricted units outstanding, beginning of period
Restricted stock units granted
Restricted stock units forfeited
Restricted stock units vested
Restricted stock units outstanding, end of period
Performance-Based Stock Units
Shares
Wtd. Avg.
Grant Price
9.02
8.33
11.09
9.14
8.60
574,916 $
100,178 $
(17,802) $
(312,447) $
344,845 $
On February 20, 2018, the Company granted 30,700 performance share units for which the number of shares earned is
based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during
the performance period from January 1, 2018 to December 31, 2020. The awards contain market conditions which allow a
payout ranging between 0% payout and 200% of the target payout. The fair value as of the date of valuation was $41.66 per
unit or 150.61% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation
using a Monte-Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price
performance achieved during the performance period. The awards have a cliff-vesting period of three years. There are no
70
71
outstanding PSUs related to this award as of December 31, 2021. During the year ended December 31, 2021 23,800 shares
vested under this award.
Lease costs represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are
classified as follows (in thousands):
On May 21, 2019, the Company granted an additional 99,500 performance-based stock units for which the number of
shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the
performance period from January 1, 2019 to December 31, 2021. The awards contain market conditions which allow a payout
ranging between 0% payout and 200% of the target payout. The fair value as of the grant date was $18.86 per unit or 112.9% of
stock price. The awards have a cliff-vesting period of three years. There were 83,600 PSUs outstanding related to this award as
of December 31, 2021. In the first quarter of 2022, the Board and its Compensation Committee approved payout of these
awards at 117% of target. Accordingly, 97,812 shares were issued on February 23, 2022.
On February 24, 2021, the Company granted 161,389 PSUs for which the number of shares earned is based on the TSR of
the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2021 to
December 31, 2022. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target
payout. The fair value as of the grant date was $13.13 per unit or 157.6% of the stock price. The compensation expense for
these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level.
The payout level is calculated based on actual stock price performance achieved during the performance period. The awards
have a cliff-vesting period of two years. All PSUs granted remain outstanding related to this award as of December 31, 2021.
As of December 31, 2021, we had unrecognized compensation expense of $1.1 million related to our performance-based
stock units based on the assumption of 100.0% target payout. The remaining weighted-average performance period is 1.0 year.
The following table provides information regarding performance-based stock unit activity for the year ended December 31,
2021:
Performance based stock units outstanding, beginning of period
Performance based stock units granted
Performance based stock units vested
Performance based stock units outstanding, end of period
Employee Savings Plan
Shares
Wtd. Avg.
Grant Price
32.48
13.13
41.66
18.84
107,400 $
161,389 $
(23,800) $
244,989 $
We have a savings plan under Section 401(k) of the Internal Revenue Code. The Company contributed on behalf of eligible
employees an amount up to 100% of the first 6% of compensation based on the contributions made by the eligible employees in
2021 and 2020. The Company's plan contributions of $0.5 million and $0.6 million for the years ended December 31, 2021 and
2020, respectively, were paid in cash during each pay period. These amounts were recorded as “General and administrative,
net” on the accompanying consolidated statements of operations.
8. Leases
SilverBow Resources has contractual agreements for its corporate office lease, vehicle fleet, drilling rigs, compressors,
treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”)
asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating
or financing lease. All of the Company’s leases are operating leases.
The initial asset and liability balances are recorded at the present value of the payment obligations over the lease term. If
lease terms include options to extend the lease and it is reasonably certain that the Company will exercise that option, the lease
term used for capitalization includes the expected renewal periods. Most leases do not provide an implicit interest rate. Unless
the lease contract contains an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease
inception to compute the fair value of the lease payments. The ROU asset balance and current and non-current lease liabilities
are reported separately on the accompanying Consolidated Balance Sheets. Certain leases have payment terms that vary based
on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. Leases with
an initial term of 12 months or less are not recorded on the balance sheet, and the Company does not account for lease and non-
lease components separately. The Company recognizes lease expense on a straight-line basis over the lease term.
Lease Costs Included in the Asset Additions in the Condensed Consolidated
Balance Sheets
Property and equipment acquisitions - short-term leases
Property and equipment acquisitions - operating leases
Total lease costs in property, plant and equipment additions
Lease Costs Included in the Condensed Consolidated Statements of
Operations
Lease operating costs - short-term leases
Lease operating costs - operating leases
General and administrative, net - operating leases
Total lease cost expensed
Year Ended
December 31, 2021
Year Ended
December 31, 2020
$
$
3,472 $
—
3,472 $
3,774
10
3,784
Year Ended
December 31, 2021
Year Ended
December 31, 2020
$
$
1,873 $
5,325
844
8,042 $
724
5,655
704
7,083
The lease term and the discount rate related to the Company's leases are as follows:
Weighted-average remaining lease term (in years)
Weighted-average discount rate
As of December 31, 2021
3.0
4.1 %
As of December 31, 2021, the Company's future undiscounted cash payment obligation for its operating lease liabilities are
as follows (in thousands):
As of December 31, 2021
2022
2023
2024
2025
2026
Thereafter
Total undiscounted lease payments
Present value adjustment
Net operating lease liabilities
$
$
$
7,757
6,468
1,200
803
689
539
17,456
(1,144)
16,312
Supplemental cash flow information related to leases was as follows (in thousands):
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows
Investing cash flows
Non-cash Investing and Financing Activities
Additions to ROU assets obtained from new operating lease liabilities
Year Ended
December 31, 2021
Year Ended
December 31, 2020
$
$
$
6,011 $
— $
8,779 $
6,352
10
1,751
Rental and lease expense was $7.0 million and $5.8 million for the years ended December 31, 2021 and 2020, respectively.
The rental and lease expense primarily relates to compressor rentals and the lease of our office space in Houston, Texas. During
2021 the Company entered into a five-year lease agreement for office space in Houston, Texas. The operating lease commenced
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73
on May 18, 2021. As of December 31, 2021, the minimum contractual obligations were approximately $3.5 million in the
aggregate.
9. Acquisitions and Dispositions
Bay De Chene Disposition
Effective December 22, 2017, the Company closed a purchase and sale contract to sell the Company's wellbores and
facilities in Bay De Chene and recorded a $16.3 million obligation related to the funding of certain plugging and abandonment
costs. Of the $16.3 million original obligation, $1.1 million and $0.8 million was paid during the years ended December 31,
2021 and 2020, respectively. The remaining obligation under this contract is $0.5 million and is carried in the accompanying
consolidated balance sheet as a current liability in “Accounts payable and accrued liabilities” as of December 31, 2021.
April 2020 Acquisition
On April 3, 2020, we acquired additional properties in the Eagle Ford for approximately $5.0 million, including assumed
liabilities. The acquisition included eight producing wells, basic infrastructure and acreage in Webb, La Salle, and McMullen
Counties. We allocated all of the purchase price to proved oil and gas properties. The Company accounted for this transaction
as an asset acquisition with the properties added to our full cost pool balance.
May 2020 Disposition
On May 13, 2020, the Company divested an overriding royalty interest in Converse and Niobrara Counties, Wyoming for
approximately $4.8 million. The sales of our Wyoming assets did not significantly alter the relationship between capitalized
costs and proved reserves, and as such, all proceeds were recorded as adjustments to our full cost pool with no gain or loss
recognized. These consolidated financial statements include the results of our Wyoming operations through the date of sale.
August 2021 Acquisition
On August 3, 2021, the Company acquired the remaining working interest in 12 wells that SilverBow operates and
additional acreage in Webb county. The total aggregate consideration was approximately $23.0 million, consisting of
$13.0 million in cash and 516,675 shares of common stock valued at approximately $10.0 million based on the Company's
share price on the closing date. Management determined that substantially all the fair value of the gross assets acquired were
concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and
allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. As a result, we
allocated substantially all of the purchase price to proved oil and gas properties.
October 2021 Acquisition
On October 1, 2021, we closed on an all-stock transaction to acquire oil and gas assets in the Eagle Ford. The acquired
assets include working interests in oil and gas properties across Atascosa, Fayette, Lavaca, McMullen and Live Oak counties.
After consideration of closing adjustments, we issued 1,341,990 shares of our common stock valued at approximately
$35.6 million, based on the Company's share price on the closing date. The acquisition was subject to further customary post-
closing adjustments. We incurred approximately $0.6 million in transaction costs for the year ended December 31, 2021.
Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and
gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on
the relative fair value of the assets acquired and liabilities assumed. As a result, we allocated substantially all of the purchase
price to proved oil and gas properties.
November 2021 Acquisition
On November 19, 2021, the Company closed on an acquisition of oil-weighted assets in the Eagle Ford (the
“Transaction”). The acquired assets included wells and acreage in La Salle, McMullen, DeWitt and Lavaca counties. After
consideration of closing adjustments, total aggregate consideration was approximately $77.4 million, consisting of
$37.6 million in cash, 1,351,961 shares of our common stock valued at approximately $37.9 million based on the Company's
share price on the closing date, and contingent consideration with an estimated fair value of $1.9 million. The contingent
consideration consists of up to three earn-out payments of $1.6 million per year for each of 2022, 2023 and 2024, contingent
upon the average monthly settlement price of WTI exceeding $70 per barrel for such year (“WTI Contingency Payout”). For
further discussion of the fair value related to the Company's contingent consideration, refer to Note 10 of these Notes to
Consolidated Financial Statements. The acquisition is subject to further customary post-closing adjustments. We incurred
approximately $0.3 million in transaction costs for the year ended December 31, 2021. Management determined that
substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have
therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value
of the assets acquired and liabilities assumed. As a result, we allocated the purchase price to proved oil and gas properties.
The following table represents the allocation of the total cost of the Transaction to the assets acquired and liabilities
assumed:
Total Cost
Cash consideration
Equity consideration
Fair value of contingent consideration
Total Consideration
Transaction costs
Total Cost of Transaction
Allocation of Total Cost
Assets
Oil and gas properties
Right of use assets
Total assets
Liabilities
Undistributed oil and gas revenues
Non-current lease liability
Asset retirement obligations
Total Liabilities
Net Assets Acquired
10. Fair Value Measurements
(in thousands)
37,581
37,923
1,855
77,359
302
77,661
78,431
1,881
80,312
344
1,881
426
2,651
77,661
$
$
$
$
$
Fair Value on a Recurring Basis. Our financial instruments consist of cash and cash equivalents, accounts receivable,
accounts payable, derivatives, the Credit Facility and the Second Lien Notes. The carrying amounts of cash and cash
equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of
these instruments.
The fair values of our derivative swap contracts are computed using observable market data whereas our derivative collar
contracts are valued using a Black-Scholes pricing model. The fair value of the WTI Contingency Payout, included within
“Other long-term liabilities” on the consolidated balance sheets, is estimated using observable market data and a Monte Carlo
pricing model. These are considered Level 2 valuations (defined below).
The carrying value of our Credit Facility and Second Lien approximates fair value because the respective borrowing rates
do not materially differ from market rates for similar borrowings. These are considered Level 3 valuations (defined below).
Fair Value on a Nonrecurring Basis. The Company applies the provisions of the fair value measurement standard on a
non-recurring basis to its non-financial assets and liabilities, including oil and gas properties acquired and assessed for
classification as a business or an asset and asset retirement obligations. These assets and liabilities are not measured at fair value
74
75
on an ongoing basis but are subject to fair value estimation when acquisitions occur or asset retirement obligations are recorded.
These are considered Level 3 valuations (defined below).
Asset retirement obligations. The initial measurement of asset retirement obligations (“ARO”) at fair value is recorded in
the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash
flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the
timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory
requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs,
inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and
political environments.
2021 and 2020 Acquisitions. The Company recognized the assets acquired in our 2021 and 2020 acquisitions at cost at a
relative fair value basis (refer to Note 9 of these Notes to Consolidated Financial Statements). Fair value was determined using
a discounted cash flow model. The underlying future commodity prices included in the Company’s estimated future cash flows
of its proved oil and gas properties were determined using NYMEX forward strip prices as of the closing date of each
acquisition. The estimated future cash flows also included management’s assumptions for the estimates of crude oil and natural
gas proved properties, future operating and development costs of the acquired properties and risk adjusted discount rates.
The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value (in millions):
Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category
have comparable fair values for identical instruments in active markets.
Level 2 – Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in
non-active markets. Instruments in this category include our commodity derivatives that we value using commonly accepted
industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other
observable market data that are obtained from independent third-party sources.
Level 3 – Uses unobservable inputs for assets or liabilities that are in non-active markets.
The following table presents our assets and liabilities that are measured on a recurring basis as of December 31, 2021 and
2020, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's
derivatives, refer to Note 5 of these Notes to Consolidated Financial Statements.
(in thousands)
December 31, 2021
Assets
Natural Gas Derivatives
Natural Gas Basis Derivatives
Oil Derivatives
Oil Basis Derivatives
NGL Derivatives
Liabilities
Natural Gas Derivatives
Natural Gas Basis Derivatives
Oil Derivatives
Oil Basis Derivatives
NGL Derivatives
WTI Contingency Payout
December 31, 2020
Assets
Natural Gas Derivatives
Natural Gas Basis Derivatives
Oil Derivatives
Oil Basis Derivatives
Liabilities
Natural Gas Derivatives
Natural Gas Basis Derivatives
Oil Derivatives
Oil Basis Derivatives
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Fair Value Measurements at
Quoted Prices in
Active markets for
Identical Assets
(Level 1)
Significant Other
Observable Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Total
1,159 $
1,025 $
371 $
3 $
449 $
31,801 $
452 $
21,330 $
514 $
1,941 $
1,841 $
1,471 $
1,135 $
2,493 $
3 $
3,967 $
416 $
5,887 $
847 $
— $
— $
— $
— $
— $
— $
— $
— $
— $
— $
— $
— $
— $
— $
— $
— $
— $
— $
— $
1,159 $
1,025 $
371 $
3 $
449 $
31,801 $
452 $
21,330 $
514 $
1,941 $
1,841 $
1,471 $
1,135 $
2,493 $
3 $
3,967 $
416 $
5,887 $
847 $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Our current and long-term unsettled derivative assets and liabilities in the table above are measured at gross fair value and
are shown on the accompanying consolidated balance sheets in “Fair value of commodity derivatives” and “Fair value of long-
term commodity derivatives,” respectively.
11. Asset Retirement Obligations
Liabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded
at fair value in the period in which they are incurred. When a liability is initially recorded, the carrying amount of the related
asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is
recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion,
and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the
obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment”
balance on our accompanying consolidated balance sheets.
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77
The following provides a roll-forward of our asset retirement obligations (in thousands):
Asset Retirement Obligations as of December 31, 2019
Accretion expense
Liabilities incurred for new wells and facilities construction
Reductions due to plugged wells and facilities
Revisions in estimates
Asset Retirement Obligations as of December 31, 2020
Accretion expense
Liabilities incurred for new wells, acquired wells and facilities construction
Reductions due to plugged wells and facilities
Revisions in estimates
Asset Retirement Obligations as of December 31, 2021
$
$
$
4,447
354
281
(103)
(5)
4,974
306
1,120
(192)
(158)
6,050
At December 31, 2021 and 2020, approximately $0.5 million and $0.4 million of our asset retirement obligations were
classified as current liabilities in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets.
Supplementary Information (unaudited)
SilverBow Resources, Inc. and Subsidiary
Oil and Gas Operations
Capitalized Costs. The following table presents our aggregate capitalized costs relating to oil and natural gas producing
activities and the related depreciation, depletion, and amortization (in thousands):
December 31, 2021
Proved oil and gas properties
Unproved oil and gas properties
Total
Accumulated depreciation, depletion, amortization and impairment
Net capitalized costs
December 31, 2020
Proved oil and gas properties
Unproved oil and gas properties
Total
Accumulated depreciation, depletion, amortization and impairment
Net capitalized costs
Total
1,588,978
17,090
1,606,068
(866,339)
739,729
1,310,008
28,090
1,338,098
(797,963)
540,135
$
$
$
$
There were $17.1 million and $28.1 million of unproved property costs at December 31, 2021 and 2020, respectively,
excluded from the amortizable base. We evaluate the majority of these unproved costs within a two- to four-year time frame.
Capitalized asset retirement obligations have been included in the Proved oil and gas properties as of December 31, 2021
and 2020.
Costs Incurred. The following table sets forth costs incurred related to our oil and natural gas operations (in thousands)
for the periods indicated:
Lease acquisitions and prospect costs
Exploration
Development
Acquisition of property(4)
(1) (3)
Total acquisition, exploration, and development
(2)
Year Ended
December 31,
2021
Year Ended
December 31,
2020
$
$
7,241 $
—
122,712
138,016
267,969 $
5,810
—
89,550
5,019
100,379
(1) Facility construction costs and capital costs have been included in development costs, and totaled $9.2 million and $4.2 million for the years ended
December 31, 2021 and 2020, respectively.
(2) Includes capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately $4.8
million and $3.5 million for the years ended December 31, 2021 and 2020, respectively. There was no capitalized interest on unproved properties for the years
ended December 31, 2021 and 2020.
(3) Includes asset retirement obligations incurred, including revisions, of approximately $0.1 million and $0.2 million for the years ended December 31, 2021
and 2020, respectively. Does not include accrued payments associated with our Bay De Chene sale for the years ended December 31, 2021 and 2020.
(4) Includes $83.5 million in equity consideration for acquisitions of property for the year ended December 31, 2021. Also includes $0.7 million in asset
retirement obligations assumed in connection with acquisitions of property for the year ended December 31, 2021.
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Supplementary Reserves Information. The following information presents estimates of our proved oil and natural gas
reserves. Reserves were prepared in accordance with SEC rules by Gruy as of December 31, 2021, 2020 and 2019. Proved
reserves, as of December 31, 2021, 2020 and 2019, were based upon the preceding 12-months' average price based on closing
prices on the first business day of each month, or prices defined by existing contractual arrangements which are held constant,
for that year's reserves calculation. The 12-month 2021 average adjusted prices after differentials used in our calculations were
$3.75 per Mcf of natural gas, $63.98 per barrel of oil, and $25.29 per barrel of NGL compared to $2.13 per Mcf of natural gas,
$37.83 per barrel of oil, and $11.66 per barrel of NGL for the 12-month average 2020 prices and $2.62 per Mcf of natural gas,
$58.37 per barrel of oil, and $16.83 per barrel of NGL for 2019.
Total
Natural Gas
Oil
NGL
Estimates of Proved Reserves
Proved reserves as of December 31, 2019
Extensions, discoveries, and other additions (3)
Revisions of previous estimates
Purchases of minerals in place
Sales of minerals in place
Production
(1)
(Mcfe)
1,420,438,811
31,651,332
(Mcf)
1,158,352,078
23,120,341
(289,880,078) (193,642,309)
11,576,517
11,576,517
(571,321)
(66,800,181)
(323,726)
(50,987,958)
(Bbls)
(Bbls)
26,613,516
17,067,606
1,079,804
342,028
(4,053,158) (11,986,475)
—
—
(1,113,881)
(41,266)
(1,521,485)
—
Proved reserves as of December 31, 2020
Extensions, discoveries, and other additions (3)
Revisions of previous estimates
(1)
1,106,415,080
948,094,943
359,374,661 . 324,625,474
12,531,501
3,930,631
13,855,188
1,860,900
(198,471,444) (199,625,710)
(1,644,367)
1,836,746
Purchases of minerals in place
226,564,990
142,794,045
10,942,051
3,019,773
Production
(78,112,880)
(60,509,606)
(1,461,657)
(1,472,222)
Proved reserves as of December 31, 2021
1,415,770,407
1,155,379,146
24,298,159
19,100,385
Proved developed reserves (2)
December 31, 2020
December 31, 2021
Proved undeveloped reserves
December 31, 2020
December 31, 2021
506,149,407
658,230,618
415,390,459
525,736,580
6,962,826
9,692,076
8,163,666
12,390,263
600,265,673
757,539,789
532,704,484
629,642,566
5,568,676
14,606,082
5,691,522
6,710,122
(1) Revisions of previous estimates are related to upward or downward variations based on current engineering information for production rates, volumetrics,
reservoir pressure and commodity pricing. The downward revisions for 2021 and 2020 were primarily attributable to the reclassification of PUDs to unproved
due to changes in the Company's five-year development plans.
(2) At both December 31, 2021 and 2020, 46% our reserves were proved developed.
(3) We have added proved reserves through our drilling activities. The 2021 additions were primarily due to additions from drilling results, leasing of adjacent
acreage and acquisitions while 2020 additions were primarily due to additions from drilling results and leasing of adjacent acreage.
Standardized Measure of Discounted Future Net Cash Flows. The Standardized Measure of discounted future net cash
flows relating to proved oil and natural gas reserves is as follows (in thousands):
Future gross revenues
Future production costs
Future development costs (1)
Future net cash flows before income taxes
Future income taxes
Future net cash flows after income taxes
Discount at 10% per annum
Standardized Measure of discounted future net cash flows relating to proved oil and
natural gas reserves
(1) These amounts include future costs related to plugging and abandoning the Company's wells.
As of December 31,
2021
2020
$
6,370,628 $
2,652,512
(1,853,856)
(1,037,498)
(753,046)
(426,849)
3,763,726
1,188,165
(584,613)
(56,576)
3,179,113
1,131,589
(1,620,651)
(618,637)
$
1,558,462 $
512,952
The Standardized Measure of discounted future net cash flows from production of proved reserves as of December 31,
2021 and 2020, were developed as follows:
1. Estimates were made of quantities of proved reserves and the future periods during which they are expected to be
produced based on year-end economic conditions.
2. The estimated future gross revenues of proved reserves were based on the preceding 12-months' average price based on
closing prices on the first day of each month, or prices defined by existing contractual arrangements.
3. The future gross revenues were reduced by estimated future costs to develop and to produce the proved reserves,
including asset retirement obligation costs, based on year-end cost estimates and the estimated effect of future income
taxes.
4. Future income taxes were computed by applying the statutory tax rate to future net cash flows reduced by the tax basis of
the properties, the estimated permanent differences applicable to future oil and natural gas producing activities and tax
carry forwards.
The Standardized Measure of discounted future net cash flows is not intended to present the fair market value of our oil and
natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in
excess of proved reserves, anticipated future changes in prices and costs, an allowance for return on investment, and the risks
inherent in reserves estimates.
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81
The following are the principal sources of changes in the Standardized Measure of discounted future net cash flows (in
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
thousands) for the years ended December 31, 2021 and 2020:
Beginning balance
Revisions to reserves proved in prior years:
Net changes in prices, net of production costs
Net changes in future development costs
Net changes due to revisions in quantity estimates
Accretion of discount
Other
Total revisions
New field discoveries and extensions, net of future production and development costs
Purchase of reserves
Sales of minerals in place
Sales of oil and gas produced, net of production costs
Previously estimated development costs incurred
Net change in income taxes
Net change in Standardized Measure of discounted future net cash flows
Ending balance
2021
512,952 $
2020
868,264
$
781,786
(360,260)
1,569
26,034
(43,379)
(112,258)
52,627
29,303
84,765
(63,944)
821,906
(425,663)
400,008
345,300
4,954
8,480
—
(1,007)
(336,028)
(124,855)
59,318
(244,994)
90,174
92,605
1,045,510
(355,312)
$ 1,558,462 $
512,952
None.
Item 9A. Controls and Procedures
We maintain disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act,
consisting of controls and other procedures designed to give reasonable assurance that information we are required to disclose
in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time
periods specified in the Securities and Exchange Commission's rules and forms and that such information is accumulated and
communicated to management, including our chief executive officer and our chief financial officer, to allow timely decisions
regarding such required disclosure.
As of the end of the period covered by this Form 10-K, the Company’s management carried out an evaluation, under the
supervision and with the participation of the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the
design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act).
Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and
procedures were effective as of the last day of the period covered by this report at the reasonable assurance level. See
management's report on internal control over financial reporting and the report of independent registered public accounting firm
at Item 8 in this Form 10-K.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting during the fourth quarter of 2021 that materially
affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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83
Item 9B. Other Information
None.
Item 9C. Disclosures Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
84
85
Item 10. Directors, Executive Officers and Corporate Governance.
PART III
The information required under Item 10 which will be set forth in our definitive proxy statement to be filed within 120 days
after the close of the fiscal year-end in connection with our May 17, 2022 annual shareholders' meeting is incorporated herein
by reference.
The Company has adopted a Code of Ethics and Business Conduct (“Code of Ethics”) which applies to our employees,
officers, directors, independent contractors and other representatives including our accounting officers and managers. The
Company has posted this Code of Ethics on its website at www.sbow.com where it also intends to post any waivers from or
amendments to this Code of Ethics, to the extent required.
Item 11. Executive Compensation.
The information required under Item 11 which will be set forth in our definitive proxy statement to be filed within 120 days
after the close of the fiscal year-end in connection with our May 17, 2022 annual shareholders' meeting is incorporated herein
by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required under Item 12 which will be set forth in our definitive proxy statement to be filed within 120 days
after the close of the fiscal year-end in connection with our May 17, 2022 annual shareholders' meeting is incorporated herein
by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required under Item 13 which will be set forth in our definitive proxy statement to be filed within 120 days
after the close of the fiscal year-end in connection with our May 17, 2022 annual shareholders' meeting is incorporated herein
by reference.
Item 14. Principal Accounting Fees and Services.
The information required under Item 14 which will be set forth in our definitive proxy statement to be filed within 120 days
after the close of the fiscal year-end in connection with our May 17, 2022 annual shareholders' meeting is incorporated herein
by reference.
Item 15. Exhibits and Financial Statement Schedules.
PART IV
1. The following consolidated financial statements of SilverBow Resources together with the report thereon of BDO USA,
LLP dated March 3, 2022, and the data contained therein are included in Item 8 hereof:
Management's Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Stockholders' Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
2. Financial Statement Schedules
None.
3. Exhibits
49
50
51
53
54
55
56
57
First Amended and Restated Certificate of Incorporation of SilverBow Resources, Inc., effective May 5, 2017
(incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.’s Form 10-Q filed May 8, 2017, File No.
001-087541).
First Amended and Restated Bylaws of SilverBow Resources, Inc., effective May 5, 2017 (incorporated by
reference as Exhibit 3.2 to SilverBow Resources, Inc.’s Form 10-Q filed May 8, 2017, File No. 001-08754).
Form of stock certificate for common stock, $0.01 par value per share.
Registration Rights Agreement, dated as of April 22, 2016, by and among SilverBow Resources, Inc. and the
stockholders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K
filed April 28, 2016, File No. 001-08754).
Registration Rights Agreement, dated as of January 26, 2017, by and among SilverBow Resources, Inc. and the
Purchasers named therein (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K
filed February 1, 2017, File No 001-08754).
Registration Rights Agreement, dated October 1, 2021, by and between SilverBow Resources, Inc. and
PetroEdge Energy IV LLC (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form S-3
filed October 8, 2021, File No 333-260142).
Registration Rights Agreement, dated October 1, 2021, by and between SilverBow Resources, Inc. and Sierra
EF, LP. (incorporated by reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form S-3 filed October 8,
2021, File No 333-260142)
Registration Rights Agreement, dated October 1, 2021, by and between SilverBow Resources, Inc. and Tri-C
Energy Partners I, LLC (incorporated by reference as Exhibit 10.3 to SilverBow Resources, Inc.’s Form S-3 filed
October 8, 2021, File No 333-260142)
Registration Rights Agreement, dated November 19, 2021, between SilverBow Resources, Inc. and TNR-CRX
STX Holdings, LLC (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form S-3 filed
November 24, 2021, File No. 333-261346)
Director Nomination Agreement, dated as of April 22, 2016, by and among SilverBow Resources, Inc. and the
stockholders party thereto (incorporated by reference as Exhibit 4.7 to SilverBow Resources, Inc.’s Form S-8
filed April 27, 2016, File No. 333-210936).
Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934, as amended.
First Amended and Restated Senior Secured Revolving Credit Agreement among SilverBow Resources, Inc., as
borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain lenders that are a party thereto
(incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.'s Form 8-K filed April 21, 2017, File
No. 001-08754).
3.1
3.2
4.1*
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9*
10.1
86
87
First Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement among SilverBow
Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent and certain lenders that are a
party thereto (incorporated by reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form 10-K filed March
1, 2018, File No. 001-08754).
Second Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement dated as of
December 15, 2017 by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as
administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as
Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed December 19, 2017 File No. 001-08754).
Third Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement dated as of April
20, 2018, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative
agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to
SilverBow Resources, Inc.’s Current Report on Form 8-K filed April 25, 2018, File No. 001-08754).
Fourth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement effective as of
November 6, 2018, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as
administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as
Exhibit 10.1 to SilverBow Resources, Inc.’s Form 10-Q filed November 7, 2018, File No. 001-08754).
Fifth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement effective as of
May 12, 2020, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as
administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as
Exhibit 10.1 to SilverBow Resources Inc's Form 8-K filed May 13, 2020, File No. 001-08754).
Sixth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement effective as of
November 2, 2020, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as
administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as
Exhibit 10.1 to SilverBow Resources, Inc.’s Form 10-Q filed November 5, 2020, File No. 001-08754).
Seventh Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement effective as of
April 16, 2021, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as
administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as
Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed April 19, 2021, File No. 001-08754).
Eighth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement effective as of
November 12, 2021, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as
administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as
Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed November 15, 2021, File No. 001-08754).
Note Purchase Agreement dated as of December 15, 2017 by and among SilverBow Resources, Inc., as issuer,
U.S. Bank National Association, as agent and collateral agent and the purchasers party thereto (incorporated by
reference as Exhibit 10.2 to SilverBow Resources, Inc.'s Form 8-K filed December 19, 2017, File No.
001-08754).
First Amendment to Note Purchase Agreement dated as of April 20, 2018, by and among SilverBow Resources,
Inc., as issuer, U.S. Bank National Association, as agent and collateral agent, the guarantors party thereto and the
purchasers party thereto (incorporated by reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form 8-K
filed April 25, 2018, File No. 001-08754).
Second Amendment to Note Purchase Agreement dated as of November 12, 2021, by and among SilverBow
Resources, Inc., as issuer, U.S. Bank National Association, as agent and collateral agent, the guarantors party
thereto and the purchasers party thereto (incorporated by reference as Exhibit 10.2 to SilverBow Resources,
Inc.’s Form 8-K filed November 15, 2021, File No. 001-08754)
Intercreditor Agreement dated as of December 15, 2017 by and among SilverBow Resources, Inc., as borrower,
certain of its subsidiaries, as grantors, JPMorgan Chase Bank, N.A., as first lien administrative agent and U.S.
Bank National Association, as second lien collateral agent (incorporated by reference as Exhibit 10.3 to
SilverBow Resources, Inc.’s Form 8-K filed December 19, 2017, File No. 001-08754).
SilverBow Resources, Inc. 2016 Equity Incentive Plan (incorporated by reference as Exhibit 4.1 to SilverBow
Resources, Inc.’s Form S-8 filed April 27, 2016, File No. 333- 210936).
Amendment to SilverBow Resources, Inc. 2016 Equity Incentive Plan, effective May 5, 2017 (incorporated by
reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed May 5, 2017, File No. 001-08754).
First Amendment to SilverBow Resources, Inc. 2016 Equity Incentive Plan, effective January 1, 2017
(incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed May 17, 2017, File No.
001-08754).
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14+
10.15+
10.16+
Second Amendment to SilverBow Resources, Inc. 2016 Equity Incentive Plan, effective April 2, 2019
(incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed May 22, 2019, File No.
001-08754).
Form of Stock Option Agreement - Emergence Grant (Type I) (incorporated by reference as Exhibit 4.2 to
SilverBow Resources, Inc.’s Form S-8 filed April 27, 2016, File No. 333-210936).
Form of Stock Option Agreement - Emergence Grant (Type II) (incorporated by reference as Exhibit 4.3 to
SilverBow Resources, Inc.’s Form S-8 filed April 27, 2016, File No. 333-210936).
Form of Restricted Stock Unit Agreement - Emergence Grant (Type I) (incorporated by reference as Exhibit 4.4
to SilverBow Resources, Inc.’s Form S-8 filed April 27, 2016, File No. 333-210936).
Form of Restricted Stock Unit Agreement - Emergence Grant (Type II) (incorporated by reference as Exhibit 4.5
to SilverBow Resources, Inc.’s Form S-8 filed April 27, 2016, File No. 333-210936).
Form of Stock Option Agreement - Non Employee Directors (incorporated by reference as Exhibit 10.2 to
SilverBow Resources, Inc.’s Form 8-K filed June 14, 2016, File No. 001-08754).
Form of Restricted Stock Unit Agreement - Officers 2019 (incorporated by reference as Exhibit 10.6 to
SilverBow Resources, Inc.’s Form 10-Q filed August 9, 2019, File No. 001-08754).
Form of Performance Restricted Stock Unit Agreement - Officers 2019 (incorporated by reference as Exhibit
10.7 to SilverBow Resources, Inc.’s Form 10-Q filed August 9, 2019, File No. 001-08754).
Form of Restricted Stock Unit Agreement – Non-Employee Directors 2020 (incorporated by reference as Exhibit
10.1 to SilverBow Resources, Inc.’s Form 10-Q filed May 7, 2020, File No. 001-08754).
Form of Cash Incentive Award Agreement – Non-Employee Directors 2020 (incorporated by reference as
Exhibit 10.2 to SilverBow Resources, Inc.’s Form 10-Q filed May 7, 2020, File No. 001-08754).
Form of Restricted Stock Unit Agreement – Officers 2020 (incorporated by reference as Exhibit 10.3 to
SilverBow Resources, Inc.’s Form 10-Q filed May 7, 2020, File No. 001-08754).
Form of Cash Performance Incentive Award Agreement – Officers 2020 (incorporated by reference as Exhibit
10.4 to SilverBow Resources, Inc.’s Form 10-Q filed May 7, 2020, File No. 001-08754).
Form of Restricted Stock Unit Agreement – Non-Employee Directors 2021 (incorporated by reference as Exhibit
10.1 to SilverBow Resources, Inc.’s Form 10-Q filed May 6, 2021, File No. 001-08754).
Form of Cash Incentive Award Agreement – Non-Employee Directors 2021 (incorporated by reference as
Exhibit 10.2 to SilverBow Resources, Inc.’s Form 10-Q filed May 6, 2021, File No. 001-08754).
Form of Performance Share Unit Agreement – Officers 2021 (incorporated by reference as Exhibit 10.3 to
SilverBow Resources, Inc.’s Form 10-Q filed May 6, 2021, File No. 001-08754).
Form of Cash Incentive Award Agreement – Officers 2021 (incorporated by reference as Exhibit 10.4 to
SilverBow Resources, Inc.’s Form 10-Q filed May 6, 2021, File No. 001-08754).
SilverBow Resources Inc. Inducement Plan (incorporated by reference as Exhibit 4.4 to SilverBow Resources,
Inc.’s Form S-8 filed December 21, 2016, File No. 333-21535).
First Amendment to SilverBow Resources, Inc. Inducement Plan, effective May 5, 2017 (incorporated by
reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form 8-K filed May 5, 2017, File No. 001-08754).
Form of Restricted Stock Unit Agreement - Inducement Plan (incorporated by reference as Exhibit 4.5 to
SilverBow Resources, Inc.’s Form S-8 filed December 21, 2016, File No. 333-21535).
Form of Stock Option Agreement - Inducement Plan (incorporated by reference as Exhibit 4.6 to SilverBow
Resources, Inc.’s Form S-8 filed December 21, 2016, File No. 333-215235).
Employment Agreement by and between SilverBow Resources, Inc. and Sean C. Woolverton, effective as of
March 1, 2017 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed
February 28, 2017, File No. 001-08754).
Amendment to Employment Agreement by and between SilverBow Resources, Inc. and Sean C. Woolverton,
effective as of April 2, 2019 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K
filed April 8, 2019, File No. 001-08754).
Employment Agreement by and between SilverBow Resources, Inc. and Steven W. Adam, effective as of
November 6, 2017 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed
November 6, 2017, File No. 001-08754).
10.17+
10.18+
10.19+
10.20+
10.21+
10.22+
10.23+
10.24+
10.25+
10.26+
10.27+
10.28+
10.29+
10.30+
10.31+
10.32+
10.33+
10.34+
10.35+
10.36+
10.37+
10.38+
10.39+
88
89
Item 16. 10-K Summary.
None.
Amendment to Employment Agreement by and between SilverBow Resources, Inc. and Steven W. Adam,
effective as of April 2, 2019 (incorporated by reference as Exhibit 10.3 to SilverBow Resources, Inc.’s Form 8-K
filed April 8, 2019, File No. 001-08754).
Employment Agreement by and between SilverBow Resources, Inc. and Christopher M. Abundis, effective as of
March 20, 2017 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed March
21, 2017, File No. 001-08754).
Amendment to Employment Agreement by and between SilverBow Resources, Inc. and Christopher M. Abundis,
effective as of April 2, 2019 (incorporated by reference as Exhibit 10.4 to SilverBow Resources, Inc.’s Form 8-K
filed April 8, 2019, File No. 001-08754).
Form of Indemnity Agreement for SilverBow Resources, Inc. directors and officers (incorporated by reference as
Exhibit 10.28 to SilverBow Resources, Inc.’s Form 10-K filed March 1, 2018, File No. 001-08754).
Purchase and Sale Agreement, dated October 8, 2021, between SilverBow Resources, Inc. and SilverBow
Resources Operating, LLC and Teal Natural Resources, LLC and Castlerock Production, LLC.
List of Subsidiaries of SilverBow Resources, Inc.
Consent of H.J. Gruy and Associates, Inc.
Consent of BDO USA, LLP.
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
The reserves letter of H.J. Gruy and Associates, Inc. dated January 21, 2022.
The following materials from SilverBow Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended
December 31, 2021 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) the Condensed
Consolidated Balance Sheets (Unaudited), (ii) the Condensed Consolidated Statements of Operations
(Unaudited), (iii) the Consolidated Statements of Stockholders Equity (Unaudited), (iv) the Condensed
Consolidated Statements of Cash Flows (Unaudited), and (v) Notes to the Condensed Consolidated Financial
Statements.
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
10.40+
10.41+
10.42+
10.43+
10.44*
21 *
23.1 *
23.2 *
31.1 *
31.2*
32#
99.1*
101*
104*
* Filed herewith.
# Furnished herewith.
+ Management contract or compensatory plan or arrangement.
90
91
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant, SilverBow
Resources, Inc., has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on
March 3, 2022.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the Registrant, SilverBow Resources, Inc., and in the capacities and on the dates indicated:
Signatures
Title
Date
SILVERBOW RESOURCES, INC.
By: /s/ Sean C. Woolverton
Sean C. Woolverton
Chief Executive Officer
/s/ Sean C. Woolverton
Sean C. Woolverton
Chief Executive Officer and Director
March 3, 2022
/s/ Christopher M. Abundis
Christopher M. Abundis
Executive Vice President,
Chief Financial Officer,
General Counsel and Secretary
March 3, 2022
/s/ W. Eric Schultz
W. Eric Schultz
/s/ Marcus C. Rowland
Marcus C. Rowland
/s/ Michael Duginski
Michael Duginski
/s/ Gabriel L. Ellisor
Gabriel L. Ellisor
/s/ David Geenberg
David Geenberg
/s/ Christoph O. Majeske
Christoph O. Majeske
/s/ Charles W. Wampler
Charles W. Wampler
Controller
March 3, 2022
Chairman of the Board
Director
March 3, 2022
Director
March 3, 2022
Director
March 3, 2022
Director
March 3, 2022
Director
March 3, 2022
Director
March 3, 2022
92
93
INVESTOR INFORMATION
BOARD OF DIRECTORS
CORPORATE HEADQUARTERS
MARCUS C. ROWLAND, CHAIRMAN OF THE BOARD
Founder and Director
IOG Capital
SILVERBOW RESOURCES, INC.
920 Memorial City Way, Suite 850
Houston, Texas 77024
MICHAEL DUGINSKI
President & Chief Executive Officer
Sentinel Peak Resources
PHONE 281-874-2700 | 888-991-SBOW
EMAIL info@sbow.com
GABRIEL L. ELLISOR
Managing Partner
3BAR Industries LLC
DAVID GEENBERG
Head of North American Investment Team
Strategic Value Partners
TRANSFER AGENT AND REGISTRAR
AMERICAN STOCK TRANSFER
& TRUST COMPANY
6201 15th Avenue
Brooklyn, New York 11219
CHRISTOPH O. MAJESKE
Director
Strategic Value Partners
CHARLES W. WAMPLER
Chief Executive Officer & President
Resource Rock Exploration II, LLC
SEAN C. WOOLVERTON
Chief Executive Officer
SilverBow Resources, Inc.
OFFICERS OF THE COMPANY
AND/OR ITS OPERATING SUBSIDIARY,
SILVERBOW RESOURCES OPERATING, LLC
EXCHANGE LISTING
NYSE: SBOW
COUNSEL
GIBSON, DUNN & CRUTCHER LLP
811 Main Street, Suite 3000
Houston, Texas 77002
INDEPENDENT AUDITOR
BDO USA, LLP
2929 Allen Parkway, 20th Floor
Houston, Texas 77019
ANNUAL MEETING
The Company’s Annual Meeting of
Shareholders will be held at 10:00 a.m. (CDT)
on Tuesday, May 17, 2022
SEAN C. WOOLVERTON
Chief Executive Officer
CHRISTOPHER M. ABUNDIS
Executive Vice President,
Chief Financial Officer,
General Counsel & Secretary
STEVEN W. ADAM
Executive Vice President &
Chief Operating Officer
STEPHEN P. SCHMITT
Vice President, Energy Marketing
SBOW.COM
SBOW.COM