STRATEGIC AIM
TARGETED RESULTS
2022 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 180,000 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.
2022 KEY HIGHLIGHTS
10+
YEARS OF
PREMIUM INVENTORY
2.2 TCFE
58% INCREASE TO
PROVED RESERVES
$5.0BN
PROVED PV-10
VALUE AT YE22
PRODUCTION & RESERVES
72%
16%
77%
270
MMCFE/D
12%
2,235
BCFE
14%
9%
52%
$5.0
BILLION
48%
PRODUCTION
PROVED RESERVES
GAS
OIL
NGL
GAS
OIL
NGL
PDP
PUD
DEAR SHAREHOLDERS:
2022 was a transformational year for SilverBow as we continued to
execute on our strategic objectives.
We significantly increased the scale of the Company through acquisitions, drilling
and leasing activity. SilverBow’s differentiated growth strategy stands out amongst
our peers after we delivered the second consecutive year of double-digit growth in
production and EBITDA. At the same time, we remained steadfast in preserving
our conservative balance sheet and being disciplined in our capital allocation.
Our efforts throughout the year delivered some of the best results in the
Company’s history.
During the first half of the year, SilverBow operated one drilling rig while simultaneously pursuing
large and accretive acquisitions. Our cross-functional teams worked tirelessly and in unison to
execute on both our successful, organic drilling program as well as a number of M&A opportunities.
In early July, concurrent to the closing of our largest acquisition to date, we added a second drilling
rig to our program, putting SilverBow on a trajectory of growth. The three acquisitions we closed in
the prior year gave us the momentum to complete four additional acquisitions in 2022, cementing
SilverBow as a consolidator across the Eagle Ford Shale.
In 2022, our development program delivered some of SilverBow’s best well results to date. In the
Austin Chalk, our wells have exceeded expectations and outperformed many of the prolific Eagle
Ford wells in the area. Our focus in the Austin Chalk this year concentrated in the dry gas window
of Webb County, where we added an additional acreage position with future drilling locations. We
believe there is opportunity to continue to delineate and develop the Austin Chalk formation across
other areas of our portfolio.
I am extremely proud of the accomplishments of our organization and the growth trajectory SilverBow
is on. Our success is built upon a strong company culture that empowers employees, incentivizes new
team-driven initiatives, and prioritizes the safety of our employees, communities and environment.
We call this the SBOWay. The SBOWay represents the core principles of our strategy.
25%
PRODUCTION GROWTH
YEAR-OVER-YEAR
60%
EBITDA GROWTH
24%
RETURN ON CAPITAL
EMPLOYED
DALLAM
SHERMAN
HANSFORD
OCHILTREE
LIPSCOMB
HARTLEY
MOORE
HUTCHINSON
ROBERTS
HEMPHILL
OLDHAM
POTTER
CARSON
GRAY
WHEELER
DEAF SMITH
RANDALL
ARMSTRONG
DONLEY
PARMER
CASTRO
SWISHER
BRISCOE
HALL
O RT H
S W
C O LLIN G
C HIL D R E S S
BAILEY
LAMB
HALE
FLOYD
MOTLEY
COTTLE
WILBARGER
FOARD
WICHITA
HARDEMAN
COCHRAN
HOCKLEY
LUBBOCK
CROSBY
DICKENS
KING
KNOX
BAYLOR
ARCHER
CLAY
MONTAGUE
COOKE
GRAYSON
FANNIN
LAMAR
RED RIVER
YOAKUM
TERRY
LYNN
GARZA
KENT
STONEWALL
HASKELL
GAINES
DAWSON
BORDEN
SCURRY
FISHER
JONES
T H R O C K M
S H AC K ELF O R D
ANDREWS
MARTIN
HOWARD
MITCHELL
NOLAN
TAYLOR
CALLAHAN
EASTLAND
N
RT O
O
YOUNG
JACK
WISE
DENTON
COLLIN
HUNT
HOPKINS
DELTA
N
I
L
K
N
A
R
F
TITUS
CAMP
S
I
R
R
O
M
STEPHENS
PALO PINTO
PARKER
TARRANT
DALLAS
ROCKWALL
RAINS
WOOD
UPSHUR
BOWIE
CASS
MARION
KAUFMAN
VAN ZANDT
HARRISON
GREGG
HOOD
JOHNSON
ELLIS
ERATH
SOMERVELL
SMITH
HENDERSON
DIMMIT
RUSK
PANOLA
LA SALLE
EL PASO
LOVING
WINKLER
ECTOR
MIDLAND
GLASSCOCK
STERLING
COKE
RUNNELS
HUDSPETH
CULBERSON
WARD
CRANE
REEVES
UPTON
REAGAN
TOM GREEN
IRION
CONCHO
COMANCHE
BOSQUE
ANDERSON
CHEROKEE
SHELBY
HILL
NAVARRO
COLEMAN
BROWN
HAMILTON
FREESTONE
NACOGDOCHES
MCLENNAN
LIMESTONE
MILLS
CORYELL
MCCULLOCH
SAN SABA
LAMPASAS
FALLS
LEON
HOUSTON
ANGELINA
JEFF DAVIS
PECOS
PRESIDIO
BREWSTER
TERRELL
N
A
S
I
E
N
T
S
U
G
U
A
SABINE
TRINITY
SAN
JACINTO
POLK
TYLER
N
O
T
W
E
N
R
E
P
S
A
J
ORANGE
WEBB
JEFFERSON
SCHLEICHER
MENARD
BURNET
MILAM
WALKER
BELL
ROBERTSON
MADISON
CROCKETT
MASON
LLANO
WILLIAMSON
BRAZOS
GRIMES
BURLESON
SUTTON
KIMBLE
GILLESPIE
BLANCO
TRAVIS
LEE
MONTGOMERY
HARDIN
WASHINGTON
LIBERTY
VAL VERDE
EDWARDS
KERR
HAYS
BASTROP
REAL
BANDERA
KENDALL
COMAL
CALDWELL
FAYETTE
AUSTIN
R
E
L
L
A
W
COLORADO
HARRIS
CHAMBERS
KINNEY
UVALDE
MEDINA
GUADALUPE
BEXAR
GONZALES
LAVACA
WILSON
DE WITT
FORT BEND
GALVESTON
WHARTON
BRAZORIA
JACKSON
MATAGORDA
MAVERICK
ZAVALA
FRIO
ATASCOSA
KARNES
DIMMIT
LA SALLE
MCMULLEN
LIVE OAK
GOLIAD
BEE
SAN PATRICIO
VICTORIA
CALHOUN
REFUGIO
ARANSAS
WEBB
DUVAL
S
L
L
E
W
M
I
J
NUECES
KLEBERG
ZAPATA
JIM HOGG
BROOKS
KENEDY
STARR
HIDALGO
WILLACY
CAMERON
FAYETTE
COLORADO
GONZALES
LAVACA
DE WITT
ATASCOSA
KARNES
MCMULLEN
LIVE OAK
New acquisitions
significantly increased
liquids production
CONSOLIDATING THE EAGLE FORD
In 2021, we closed three transactions which bolstered existing acreage positions and extended our
operating area into the oil window of the Eagle Ford Shale. In 2022, we carried this momentum forward
and closed four additional transactions totaling nearly $600 million in deal value. Through the 2022
acquisitions, we added over 350 gross drilling locations across a balanced mix of oil and gas as well
as Eagle Ford and Austin Chalk formations.
These acquisitions further our strategic objectives on numerous fronts. The industrial logic of
consolidating highly contiguous acreage and adding a second drilling rig significantly increased the
scale of our operations and drove further cost synergies at the field and corporate level. The additional
inventory from these acquisitions expanded our balanced portfolio, with approximately two-thirds
of our locations being liquids-weighted at year-end 2022. Most importantly, the acquisitions were
accretive across all key financial metrics and added meaningful shareholder value.
Through bolt-on acquisitions, leasing and drill-to-earn agreements, SilverBow established two
premium acreage positions in 2022. In September, SilverBow announced a new dry gas area in
Webb County that doubled the Company’s
acreage to approximately 15,000 net acres.
Subsequently, in October, SilverBow added
new acreage and incremental working interest
across a contiguous 17,000 net acre position in
the Karnes Trough area, providing for extended
laterals and optimized well design. These areas
are primed for future full-scale development
programs targeting stacked formations on
multi-well pads.
GROWING THROUGH
2022 ACQUISITIONS & LEASING
ADDED TO INVENTORY
+375 DRILLING LOCATIONS
MBBLS/D OF
+7.7
+355 BCFE ADDED TO YE22
LIQUIDS PRODUCTION
PROVED RESERVES
Our Webb County gas and recent
Austin Chalk development will
continue to be a key focus area of
long-term growth
DIFFERENTIATED GROWTH STRATEGY
As a result of our efforts leading in-basin consolidation, we have built premiere acreage positions in
the dry gas, condensate and oil commodity windows of the Eagle Ford Shale. Year-over-year, our
inventory increased by over 75%. Our 2022 production and EBITDA increased by 25% and 60%
year-over-year, respectively. We continued to see the highest returns on our capital deployment
through the drillbit and accretive acquisitions and reinvested portions of our free cash flow throughout
the year towards strategic leasing. Our development program supports continued growth.
In addition to the rapid growth, SilverBow has differentiated itself with its commodity mix as well. In
prior years, natural gas comprised 75% to 80% of SilverBow’s production mix. By the end of 2022,
natural gas represented approximately 66% of our production mix, as SilverBow’s acquisition and
development activity drove 2022 oil production 80% higher year-over-year.
PROVED RESERVES AND BALANCE SHEET STRENGTH
SilverBow’s SEC proved reserves reflect the value added through our growth strategy. Year-end
2022 total proved reserves of 2.2 Tcfe increased by 58% year-over-year, and our proved PV-10 value
of approximately $5 billion increased 173% over the same time period. Notably, our 2022 acquisitions
added over $1 billion to our year-end proved PV-10 value.
Core to our strategy is maintaining a conservative balance sheet with low leverage levels and ample
liquidity for our operations. We funded approximately $375 million of 2022 cash acquisition costs
while holding our leverage at 1.35x, nearly flat compared to year-end 2021. Furthermore, our borrowing
base increased by $315 million year-over-year to $775 million, and at year-end 2022 we had over
$225 million of liquidity. We believe that delivering outsized growth in conjunction with a disciplined
balance sheet management separates SilverBow from our peers.
CORPORATE RESPONSIBILITY
SilverBow maintained safe operations notwithstanding an increase in
activity and integration of new assets into our operations. Our 2022 TRIR of
2020
2021
0.09 reflects our “Safety Strong” standards, and SilverBow’s production
operations team recently celebrated its sixth anniversary with zero OSHA
recordable accidents. Responsibility for our environment, our communities and our employees is
ingrained within SilverBow’s culture the SBOWay. In December, we published ESG metrics aligned
with SASB and GRI reporting standards. In the first half of 2023, we plan to publish our inaugural ESG
report. We recently expanded our Board of Directors to nine directors, adding to the independence,
skill sets, experiences and gender diversity of our Board. Finally, our SilverBow Cares initiative
supported over 30 charitable organizations in 2022. In the coming year, plans exist to further our
environmental improvements by relying on pneumatic controllers, flare efficiencies and continuous
emissions monitoring opportunities.
IN SUMMARY AND LOOKING AHEAD
Throughout the last several years, SilverBow has remained true to its balanced strategy and multi-year
objectives. We have (i) increased scale through double digit production and EBITDA growth while living
within cash flow; (ii) expanded high-return inventory through accretive acquisitions and leasing activity;
(iii) optimized capital efficiencies and cost structure; and (iv) maintained balance sheet strength. The
net result was a return on capital employed of 24% for 2022.
A WORD OF THANKS
I would like to take this opportunity to thank all our shareholders, our neighbors
in the communities in which we operate and the SilverBow team. Our success
is built on the hard work and dedication of “One Team” and the trust of our
partners.
Thank you,
Sean Woolverton,
Chief Executive Officer
FORM 10-K
STRATEGIC AIM
TARGETED RESULTS
2022 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, 2022
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
Preferred Stock Purchase Rights
SBOW
None
New York Stock Exchange
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
1
reporting
company,”
and
“emerging
growth
company”
in Rule
12b-2
of
the
Exchange Act.
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
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
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements
of the registrant included in the filing reflect the correction of an error to previously issued financial statements. o
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-
based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant
to §240.10D-1(b). o
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, 2022, the last business day of the second quarter
for fiscal year 2022, was approximately $492,145,402.
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 February 24, 2023 was 22,473,737.
Documents incorporated by reference: Portions of the registrant’s definitive proxy statement for its 2023 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.
2
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
6
21
36
37
37
37
39
40
49
50
89
89
89
91
92
92
92
92
92
93
93
3
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, well expectations and drilling plans, estimated production levels, expected oil and natural gas
pricing, estimated oil and natural gas reserves or the present value thereof, reserve increases, service costs, impact of inflation,
capital expenditures, budget, projected costs, prospects, plans and objectives of management are forward-looking statements.
When used in this report, the words “will,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “budgeted,” “guidance,”
“expect,” “may,” “continue,” “predict,” “potential,” “plan,” “project,” “should” 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:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
further actions by the members of the Organization of the Petroleum Exporting Countries (“OPEC”), Russia and other
allied producing countries (together with OPEC, “OPEC+”) with respect to oil production levels and announcements
of potential changes in such levels;
risks related to recently completed acquisitions and integration of these acquisitions;
volatility in natural gas, oil and natural gas liquids prices;
ability to obtain permits and government approvals;
our borrowing capacity, future covenant compliance, cash flow and liquidity, including our ability to satisfy our short
or long-term liquidity needs;
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;
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 and storage capacity 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 inflationary pressures, further increases in interest rates, a general
economic slowdown or recession, political tensions and war (including future developments in the ongoing Russia-
Ukraine conflict);
the severity and duration of world health events, including health crises and pandemics including the COVID-19
pandemic, related economic repercussions, including disruptions in the oil and gas industry, supply chain disruptions,
and operational challenges including remote work arrangements and protecting the health and well-being of our
employees;
opportunities to monetize assets;
our ability to execute on strategic initiatives;
effectiveness of our risk management activities including hedging strategy;
counterparty and credit market risk;
pending legal and environmental matters, including potential impacts on our business related to climate change and
related regulations;
actions by third parties, including customers, service providers and shareholders;
current and future 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
•
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, 2022 (this “Form 10-K”).
Many of the foregoing risks and uncertainties, as well as risks and uncertainties that are currently unknown to us, are, and
may be, exacerbated by the ongoing Russia-Ukraine conflict, increasing economic uncertainty, recessionary and inflationary
pressures, continuing effects of 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 Form 10-K 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 Form 10-K for the year ended December 31, 2022. 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, except as required by law.
5
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 36 and
37 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 reorganized 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 180,000 net acres across five 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 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 315 million cubic feet of natural gas equivalent per day (“MMcfe/d”) during the fourth
quarter of 2022 and had proved reserves of 2,235 Bcfe (77% natural gas) with a Standardized Measure of $4.0 billion and a
PV-10 of $5.0 billion at SEC pricing as of December 31, 2022. 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, landowner relations and the 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 and Austin Chalk drilling locations. As of
December 31, 2022, our technical team has an average of approximately 16 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. Concentrating solely on
the Eagle Ford Shale and Austin Chalk 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 Shale 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 2023 capital budget range of $450-$475 million provides for drilling 60 gross
(52 net) horizontal wells which is expected to be funded primarily from operating cash flow and borrowings under our
Credit Facility.
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. Our diversification strategy 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 strength in commodity prices in 2022, the Company's drilling and completion
(“D&C”) program emphasized both oil and gas development. Of the 656 gross horizontal drilling locations at year-end
2022, 430 are oil locations and 226 are gas locations. 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 contiguous 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
6
operational control is critical for us to be able to transfer successful D&C 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 hubs.
•
•
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 four notable acquisitions in 2022. These acquisitions, in aggregate,
added 3,800 barrels per day (Bbls/d) and 14 million cubic feet per day (“MMcf/d”) to the Company’s full year 2022 net
production. This represented 14% of the Company's 2022 net production. SilverBow expects these acquisitions to
comprise a greater percentage of its 2023 net production.
In total the Company paid $367.0 million in cash and issued $156.3 million in equity related to these transactions. We
plan to continue strategically targeting certain areas of the Eagle Ford Shale and Austin Chalk where our technical
experience and successful drilling results can be replicated and expanded. We believe our extensive basin-wide experience
and relationships 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 and funds available on our Credit Facility (as defined in Note 4 to the
Company's consolidated financial statements in this Form 10-K). As of December 31, 2022, 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 2023 development plan and opportunistically acquire or lease
additional acreage. Our Credit Facility and Second Lien (as defined in Note 4 to the Company's consolidated financial
statements in this Form 10-K), maturing in October 2026 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. 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 24, 2023, we had approximately 73% of total production volumes hedged for full
year 2023, using the midpoint of the Company's production guidance of 325 - 345 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, 2022, we had approximately 180,000 net acres in the Eagle Ford Shale and
Austin Chalk and 656 gross horizontal drilling locations, representing over 10 years of core premium inventory at a two-
rig pace. Approximately 57% of our estimated proved reserves at December 31, 2022 were undeveloped. We operate
essentially all of our proved reserves and have an average working interest of approximately 90% 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 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. The ability to adjust our D&C schedule in response
to management's outlook and view of commodity prices allows us to focus on the highest return, lowest risk projects. In
2022, we drilled 45 net wells, completed 39 net wells and brought 37 net wells online. The Company operated one drilling
rig through the first half of 2022 and added a second rig in conjunction with the closing of the acquisition of substantially
all of the oil and gas assets of Sundance Energy, Inc. and its affiliated entities (collectively, “Sundance”) on June 30,
2022. At the beginning of October, the Company moved both its drilling rigs to its Webb County Gas area. This decision
was based on the continued strong Austin Chalk results in the Dorado play.
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 2022 our average natural
gas basis differentials to NYMEX were $0.28/Mcf discount versus $1.25/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.
7
•
•
•
Experienced and proven technical team. As of December 31, 2022, we employed 17 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 16 years of experience in their technical fields. Our technical team has
come from a number of large and successful organizations. They are 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 position is contiguous in nature which allows us 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 robust liquidity. As of December 31, 2022, 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 2023 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
October 2026 and December 2026, respectively, are our only debt maturities. As of December 31, 2022, we had $542.0
million drawn on our $775.0 million borrowing base under the Credit Facility.
Property Overview
SilverBow's operations are focused in five operating areas across South Texas. The following table sets forth information
regarding its Eagle Ford Shale and Austin Chalk assets in 2022:
Operating Areas
Webb County Gas
Western Condensate
Southern Eagle Ford
Central Oil
Eastern Extension
Other (1)
Total
(1) Other includes non-core properties
Net Acreage
2022
Production
(Mcfe/d)
Gas as % of
2022
Production
2022 Net Wells
Drilled
2022 Net Wells
Completed
139,419
100 %
40 %
80 %
14 %
27 %
29 %
72 %
24
7
—
14
—
—
45
20
7
1
10
—
1
39
12,943
30,844
52,135
66,759
17,306
—
49,359
33,877
37,472
8,723
905
179,987
269,755
8
The following table sets forth information regarding the Company's 2022 year-end proved reserves of 2,234.6 Bcfe and
production of 98.5 Bcfe by area:
Operating Areas
Webb County Gas
Western Condensate
Southern Eagle Ford
Central Oil
Eastern Extension
Other (1)
Total
(1) Other includes non-core properties
Oil and Natural Gas Reserves
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)
507.6
149.3
110.4
137.7
41.1
6.8
925.3
1,432.9
64.1 %
58.6
44.5
141.9
111.4
—
207.9
154.9
279.6
152.5
6.8
9.3 %
6.9 %
12.5 %
6.8 %
0.3 %
952.8
1,281.8
2,234.6
100.0 %
— %
60.4 %
23.1 %
85.3 %
70.4 %
29.6 %
22.8 %
50.9
18.0
12.4
13.7
3.2
0.3
98.5
The following tables present information regarding proved oil and natural gas reserves attributable to SilverBow's
interests in proved properties as of December 31, 2022, 2021 and 2020. 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, 2022, 2021 and 2020.
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 2022, 2021 and 2020 reserve reports. To achieve reasonable certainty for our reserve
estimates, we and Gruy employ technologies that have been demonstrated to yield results with consistency and repeatability
and use standard engineering technologies and methods, which are generally accepted by the petroleum industry. The
technologies and economic data used to calculate our proved reserves estimates include, but are not limited to, well logs,
production tests, seismic data and core data. Our proved reserves additions are prepared using extrapolation of established
historical production trends from offsetting producing wells, with similar completions, in analogous reservoirs. Reasonable
certainty is further confirmed by applying one or more of these supplemental methods: reservoir modeling which may include
analytical and numerical methods, rate transient analysis and geoscience examination, including petrophysical analysis to
confirm reservoir continuity. 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 2022, 2021 and 2020 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
2022, 2021 and 2020 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, 2022, 2021 and 2020 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
9
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 2022 average adjusted prices after differentials were $6.14 per Mcf of natural gas, $94.36 per barrel of
oil, and $34.76 per barrel of NGL, compared to $3.75 per Mcf of natural gas, $63.98 per barrel of oil, and $25.29 per barrel of
NGL for 2021 and $2.13 per Mcf of natural gas, $37.83 per barrel of oil, and $11.66 per barrel of NGL for 2020.
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,
2022
2021
Standardized Measure of Discounted Future Net Cash Flows
$
4,040 $
1,558 $
Adjusted for: Future income taxes (discounted at 10%)
PV-10 Value
924
259
$
4,964 $
1,817 $
2020
513
13
526
10
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,
2022, 2021 and 2020. 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, 2022, SilverBow had estimated proved reserves of 2,235 Bcfe with a Standardized Measure of $4.0
billion and PV-10 Value of $5.0 billion. This is an increase of approximately 819 Bcfe from the Company's year-end 2021
proved reserves quantities primarily due to increases in our reserves primarily from our acquisitions during the year.
SilverBow's total proved reserves at December 31, 2022 were approximately 14% crude oil, 77% natural gas, and 9% NGLs,
while 43% 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
2022
As of December 31,
2021
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
695,482
1,030,071
1,725,553
525,737
629,643
1,155,380
23,360
28,829
52,189
19,523
13,133
32,656
9,692
14,606
24,298
12,390
6,710
19,100
2020
415,390
532,704
948,094
6,963
5,569
12,532
8,164
5,692
13,855
Total Estimated Reserves (MMcfe)
(1)
2,234,624
1,415,771
1,106,415
Standardized Measure of Discounted Future Net Cash Flows (in
millions) (2)
$
4,040 $
1,558 $
513
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, 2022, 2021 and 2020 are net of $6.1 million, $3.5 million and $2.2 million of plugging
and abandonment costs, respectively.
2,579 $
2,385
4,964 $
1,031 $
786
1,817 $
382
144
526
$
$
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.
11
Proved Undeveloped Reserves
The following table sets forth the aging of SilverBow's proved undeveloped reserves as of December 31, 2022:
Volume
(Bcfe)
% of PUD
Volumes % of PV-10
Year Added
2022
2021
2020
2019
2018
Total
664.4
372.4
78.8
131.3
34.9
1,281.8
52 %
29 %
6 %
10 %
3 %
100 %
51 %
31 %
5 %
11 %
2 %
100 %
During 2022, the Company's proved undeveloped reserves increased by approximately 524.3 Bcfe primarily due to
increases in our natural gas reserves from extensions of 513.5 Bcfe (121.0 Bcfe as a result of successful drilling on existing
leases and 392.5 Bcfe related to new adjacent leases acquired in 2022), acquisitions of approximately 149.3 Bcfe and positive
revisions of approximately 13.6 Bcfe. The increases were partially offset by negative revisions of 2.8 Bcfe related to changes
in the development plan. Further, SilverBow incurred approximately $165.5 million in capital expenditures (excluding
acquisitions) during the year which resulted in the conversion of 149.3 Bcfe of its December 31, 2021 proved undeveloped
reserves to proved developed reserves, primarily in our Webb County Gas area. 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.
We maintain a five-year development plan adopted by our management, which includes proved undeveloped locations in
our reserve report that are scheduled to be drilling within five years from the year they were initially disclosed. The
development plan is reviewed annually to ensure capital is allocated to the wells that have the highest risk-adjusted rates of
return within our inventory of undrilled well locations. As of December 31, 2022, no material amount of proved undeveloped
reserves were not scheduled to be converted to proved developed status within five years from the year they were initially
disclosed.
The PV-10 Value from the Company's proved undeveloped reserves was $2,384.6 million at December 31, 2022, which
was approximately 48% of its total PV-10 Value of $5.0 billion.
Sensitivity of Reserves to Pricing
As of December 31, 2022, a 5% increase in natural gas pricing would increase SilverBow's total estimated proved
reserves by approximately 1.8 Bcfe and would increase the PV-10 Value by approximately $235.3 million. Similarly, a 5%
decrease in natural gas pricing would decrease the Company's total estimated proved reserves by approximately 1.9 Bcfe and
would decrease the PV-10 Value by approximately $235.2 million.
As of December 31, 2022, a 5% increase in oil and NGL pricing would increase SilverBow's total estimated proved
reserves by approximately 3.4 Bcfe, and would increase the PV-10 Value by approximately $154.7 million. Similarly, a 5%
decrease in oil and NGL pricing would decrease the Company's total estimated proved reserves by approximately 7.2 Bcfe and
would decrease the PV-10 Value by approximately $153.7 million.
This sensitivity analysis is as of December 31, 2022 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, 2022 that may require revisions to
estimates of proved reserves.
12
Oil and Gas Wells
The following table sets forth the total productive gross and net wells in which SilverBow owned an interest at the
following dates:
December 31, 2022
Gross (1)(2)
Net (3)
December 31, 2021
Gross (1)(2)
Net (3)
December 31, 2020
Gross (1)(2)
Net (3)
Oil Wells
Gas Wells
Total
Wells(1)
442
385.7
174
145.9
103
100.9
453
387.4
352
279.6
266
216.9
895
773.1
526
425.5
369
317.8
(1) Excludes 11, 8, and 8 service wells in 2022, 2021 and 2020, respectively.
(2) Includes 78, 15 and 10 gross productive but not producing total wells as of December 31, 2022, 2021 and 2020, respectively
(3) Includes 63, 10 and 9 net productive but not producing total wells as of December 31, 2022, 2021 and 2020, respectively
Oil and Gas Acreage
The following table sets forth the developed and undeveloped leasehold acreage held by the Company at December 31,
2022:
Texas (1)
(1) The Company's total Texas acreage is located in the Eagle Ford field.
Developed
Undeveloped
Gross
Net
Gross
Net
183,762
146,370
33,618
33,618
As of December 31, 2022, SilverBow's net undeveloped acreage in Texas subject to expiration, if not renewed, is
approximately 76% in 2023, 13% in 2024, 3% in 2025 and 8% in 2026 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.
13
Drilling and Other Exploratory and Development Activities
The following table sets forth the results of the Company's drilling and completion activities during the years ended
December 31, 2022, 2021 and 2020:
Year
Type of Well
Total
Gross Wells
Productive
Dry
Total
Net Wells
Productive
Dry
2022
Exploratory
Development
2021
Exploratory
Development
2020
Exploratory
Development
—
47
—
21
—
19
—
—
47 —
—
—
21 —
—
19
—
—
—
45.2
—
18.7
—
14.8
—
—
45.2
—
—
—
18.7
—
—
—
14.8
—
Recent Activities
As of December 31, 2022, SilverBow was in the process of drilling 4 wells in our Central Oil and Western Condensate
areas where we have a 100% working interest. These wells were completed in the first quarter of 2023.
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 2022 totaled
$8.8 million and ranged from $51 to $1,711 per well per month.
14
Marketing of Production
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,
2022 and 2021, 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, 2022
Year Ended
December 31, 2021
22 %
11 %
*
14 %
12 %
26 %
10 %
15 %
16 %
12 %
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, La Mesa and Northern
Webb 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.
The Company 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 Company has gas processing and gathering agreements with Targa Resources Corp. and DCP South Central Texas,
LLC 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 and processing agreement with Copano Energy (Kinder Morgan) for the majority of its
gas in the Shiner, Texas area, as well as a gas gathering and processing agreement with Energy Transfer LP. Oil production is
transported to market by truck and sold at prevailing market prices.
In its Central Oil-Oak area, the Company has agreements with various entities affiliated with Enterprise Products Partners,
L.P. (“Enterprise”) entities that provide for the gathering of oil and natural gas, the processing of natural gas and the
transportation of residue gas to sales points. The oil is sold at a central field facility into an Enterprise crude pipeline.
15
The following table summarizes production volumes, sales prices before the effect of derivatives, and production cost
information for SilverBow's net oil, NGL and natural gas production for the years ended December 31, 2022, 2021 and 2020:
All Operating Areas
Year Ended December 31,
2021
2020
2022
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)
2,634
1,950
70,958
98,460
1,462
1,472
60,510
78,113
$
$
$
$
$
90.84 $
31.96 $
6.37 $
7.65 $
67.46 $
27.78 $
4.42 $
5.21 $
0.91 $
0.66 $
1,521
1,114
50,988
66,800
37.89
13.02
2.06
2.66
0.63
(1) Average production cost includes lease operating costs, transportation and gas processing costs but excludes severance and ad valorem taxes.
The following table provides a summary of the Company's production volumes, average sales prices before the effect of
derivatives, and average production costs for its areas with proved reserves greater than 15% of total proved reserves. This
area, which is inclusive of our Fasken, La Mesa, Northern Webb and Rio Bravo fields, accounts for approximately 64% of
SilverBow's proved reserves based on total MMcfe as of December 31, 2022:
Webb County Gas Area
Year Ended December 31,
2021
2020
2022
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)
1
50,879
50,888
2
42,933
42,943
$
$
$
$
33.28 $
6.38 $
6.39 $
24.55 $
4.53 $
4.53 $
0.57 $
0.56 $
2
35,399
35,410
10.41
2.03
2.03
0.56
(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
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adversely affect SilverBow. Refer to “Risk Factors” in Item 1A 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 prices
through the fourth quarter of 2024 and natural gas prices through the fourth quarter of 2025. We believe SilverBow also has
sufficient protection in place to protect against volatility in natural gas liquids prices through the fourth quarter of 2024. With
regards to natural gas prices, there are regular patterns of price fluctuation throughout the year. Seasonality, especially with
regards to weather, helps the Company manage its physical volume exposure as well as financial price risk in the market. By
anticipating seasonality, the Company can adjust its operations and look to reduce its financial risks. Supply, demand and
storage are the three major factors used in analyzing commodity risk. Gas production is relatively stable, but may experience
unexpected disruptions such as unscheduled pipeline maintenance or extreme weather. 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:
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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;
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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,
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” in 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
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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.
Human Capital
As SilverBow employees are critical to our success, the Company is committed to its workforce and seeks to support both
its employees and contractors through its corporate culture, known as “the SBOWay.” The SBOWay is built on five tenets:
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One Team;
Unleash Potential;
Drive Value;
Lead the Way, and
Safety Strong
These core tenets help drive SilverBow’s human capital management and, in turn, enhance the Company’s tenet to “Drive
Value” for the organization. The Company’s human resources department manages the human capital initiatives with the
support and direction from SilverBow’s senior management team. SilverBow has established internal committees, comprised
of employees from all levels of the Company, that serve to shape and maintain the culture. These committees include: the
SBOWay Committee, which is responsible for maintaining the culture, the SilverBow Cares Committee, which is responsible
for maintaining the Company’s community outreach programs, and the SilverBow Employee Association, which is tasked
with employee engagement and teambuilding. Senior management also reinforces the SBOWay culture through quarterly
townhalls and monthly emails on a specific cultural tenet. Ultimately, SilverBow’s Board of Directors oversees the Company’s
human capital management practices, receiving periodic updates on workforce-related topics.
Diversity and Inclusion
Overall, the Company is committed to be a workplace of inclusion, with a diversity of skill, viewpoints, backgrounds,
experiences and demographics. SilverBow’s SBOWay culture and “One Team” mentality provides the underlying framework
to support and build upon the Company’s dedication to a diverse workplace that fosters the attraction and retention of unique
talents, personalities, work experiences, perspectives, culture, race, gender, sexual orientation and other differences to the
Company. The Company endeavors to create a workplace where employees treat each other with mutual respect. As stated in
SilverBow’s Code of Ethics and Business Conduct, the Company is committed to being an equal opportunity employer and
discriminating against any employee or person with whom SilverBow does business on the basis of age, race, color, religion,
sex (including gender, pregnancy, sexual orientation and gender identity), disability, national origin, genetic information,
covered veteran status or other legally protected characteristic is not permitted. Additionally, the Company recently added to
the diversity of skills, experience and gender on our Board of Directors as we expanded to nine directors.
Health and Safety
As exemplified by the tenet “Safety Strong,” the health and safety of SilverBow’s workforce is a priority. In establishing a
safe workplace, SilverBow has implemented health, safety and environmental management processes into its operations to
promote workplace safety. All individuals are authorized with a “stop work” authority and personnel are often recognized for
reporting any potentially unsafe or unhealthy conditions and taking steps to correct those conditions. Further, during the height
of 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; the Company has integrated some of these measures following the pandemic
for the general health and safety of employees. The Company also promotes mental health, including an employee assistance
program and an initiative each May in respect of mental health awareness month.
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Training and Development
SilverBow understands that to attract and retain the best talent, it must provide opportunities for people to grow and
develop, which is exemplified through its core tenet of “Unleash Potential.” Accordingly, the Company provides career
development programs, encompassing the development of technical and management skills. This includes professionally
facilitated leadership and other trainings offered, external technical and special trainings, along with educational assistance for
continuing education.
Compensation and Benefits
SilverBow’s compensation and benefits program is designed to recruit and retain talented employees for our business. The
Company has recognized the importance of providing competitive benefits that support the wellbeing, medical and financial
health of its employees. Our compensation program is routinely benchmarked versus our peers and the local job markets to
ensure it recognizes and rewards both Company and individual employee performance. The program consists of: competitive
base salaries, an annual bonus program, recognition awards for achievement, and long-term performance incentives. The
Company’s portfolio of benefits includes: medical, dental and vision insurance plans for employees and their families, a
401(k) plan with a competitive Company match, life insurance, short-term and long-term disability plans, paid time off for
holidays, vacation and sick leave and medical savings accounts.
Annually, in accordance with our “Lead the Way” tenet, the Company surveys its employees on benefits, 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 continues to
offer a flexible and hybrid work-from-home schedule post-pandemic for our corporate employees. SilverBow was recognized
as a 2022 top workplace by the Houston Chronicle based on employee survey responses, representing the third year that the
Company achieved this distinction. Based on employee feedback and designed to provide employees with a holistic approach,
the Company also offers unique wellness benefits, charitable donation proposal opportunities and even a one-time wills and
estate planning benefit to all employees in 2022.
Workforce and Relations
As of December 31, 2022, the Company employed 82 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.
Facilities
At December 31, 2022, 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 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. Information contained in SilverBow's website is not part of this report or any other filings with the SEC.
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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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the domestic and foreign supply of oil and natural gas;
the price and quantity of foreign imports of oil and natural gas;
actions by OPEC+ with respect to oil production levels and announcements of potential changes in such levels;
the level of consumer product demand, including as a result of competition from alternative energy sources;
the level of global oil and natural gas exploration and production activity;
domestic and foreign governmental regulations, including regulations in connection with a response to climate change;
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 the continuing economic and financial impacts
of the COVID-19 pandemic;
technological advances affecting oil and natural gas production and consumption;
overall U.S. and global economic and political conditions, including inflationary pressures, further increases in interest
rates, a general economic slowdown or recession, political tensions and war (including future developments in the
ongoing Russia-Ukraine conflict);
the price and availability of alternative fuels; and
trade relations and policies, including the imposition of tariffs by the United States or others.
Prices for oil and natural gas are particularly sensitive to actual and perceived threats to geopolitical stability and to
changes in production from OPEC+ member states. For example, the ongoing conflict, and the continuation of, or any increase
in the severity of, the conflict between Russia and Ukraine, has led and may continue to lead to an increase in the volatility of
global oil and natural gas prices.
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.
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 2023 capital plan, including expenditures for leasehold
acquisitions, drilling and infrastructure and fulfillment of abandonment obligations, is expected to be between $450-$475
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million. In 2022, we had approximately $327.5 million of capital expenditures excluding acquisitions. 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 25,566 net acres in Texas that could
potentially expire during fiscal year 2023, representing approximately 76% of our total net undeveloped acreage in Texas of
33,618 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
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 2022 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 (including events that may be caused or exacerbated by climate
change);
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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fires and explosions; and
personal injuries and death.
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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, unavailability or the high cost of drilling rigs, equipment, supplies or personnel, have delayed and adversely
affected and could continue to 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
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, or any other health crisis, the 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, the adoption of new or revised employment and labor laws and regulations (including increased minimum wage
requirements) or government programs, the 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 the past, Texas
has experienced severe droughts that have limited the water supplies that are necessary to conduct hydraulic fracturing. 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.
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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. Geopolitical
tensions or conflicts, such as Russia's invasion of Ukraine, may further heighten the risk of cyber attacks.
We have experienced, and expect to continue to experience, 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. Further, cyber attacks on a communications network or power grid could cause operational
disruption resulting in loss of revenues. 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, making us vulnerable to risks
associated with operating in one geographic area. A number of our properties could experience any of the same adverse
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 maintenance or interruption of transportation of crude oil or natural gas produced from wells in the
Eagle Ford and Austin Chalk. For example, a decrease in commodity prices or an excess supply of oil and natural gas in South
Texas could result in a temporary curtailment or shut-in of our production or an inability to obtain favorable terms for delivery
of the natural gas and oil we produce. Such delays, curtailments, shortages 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, 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 potential unknown
liabilities and unforeseen expenses, the possibility that management may be distracted from regular business concerns by the
need to integrate operations and systems and 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
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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.
Health crises and pandemics, such as the COVID-19 pandemic, have adversely affected, and may continue to adversely
affect, our business, financial position, results of operations and financial condition.
The initial phase of the COVID-19 pandemic caused 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, caused, and may continue to cause, extreme market volatility and a substantial adverse effect on
commodity prices. 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. Additionally, health crises and pandemics contributed to, and may continue to contribute to, a
shortage of equipment, supplies, labor and services. The extent to which our financial condition and results of operations will
continue to be affected by the COVID-19 pandemic or any future health crisis will depend on various factors, many of which
are uncertain and cannot be predicted, such as the duration, severity and sustained geographic resurgence of the subject virus
and any government policies and restrictions implements in reaction to such virus.
Our commitments and disclosures related to sustainability expose us to numerous risks.
We have made, and will continue to make, commitments and disclosures related to sustainability matters. The Company
published an inaugural Sustainability Accounting Standards Board (“SASB”) and Global Reporting Initiative (“GRI”) inaugural
report in 2022 and plans to publish an inaugural sustainability report in the first half of 2023. Statements related to
sustainability goals, targets and objectives reflect our current plans and do not constitute a guarantee that they will be achieved.
Our efforts to research, establish, accomplish, and accurately report on these goals, targets, and objectives expose us to
numerous operational, reputational, financial, legal, and other risks. Our ability to achieve any stated goal, target, or objective,
including with respect to emissions reduction, is subject to numerous factors and conditions, some of which are outside of our
control. Examples of such factors include: (1) the extent our customers' decisions directly impact, relate to, or influence the use
of our equipment that creates the emissions we report, (2) the availability and cost of low- or non-carbon-based energy sources
and technologies, (3) evolving regulatory requirements affecting sustainability standards or disclosures, (4) the availability of
suppliers that can meet our sustainability and other standards. In addition, standards for tracking and reporting on sustainability
matters, including climate-related matters, have not been harmonized and continue to evolve. Our processes and controls for
reporting sustainability matters may not always comply with evolving and disparate standards for identifying, measuring, and
reporting such metrics, including sustainability-related disclosures that may be required of public companies by the SEC, and
such standards may change over time, which could result in significant revisions to our current goals, reported progress in
achieving such goals, or ability to achieve such goals in the future. Changes in such standards may also require us to alter our
accounting or operational policies and to implement new or enhance existing systems to reflect new reporting obligations. Our
business may also face increased scrutiny from investors and other stakeholders related to our sustainability activities, including
the goals, targets, and objectives that we announce, and our methodologies and timelines for pursuing them. If our sustainability
practices do not meet investor or other stakeholder expectations and standards, which continue to evolve, our reputation, our
ability to attract or retain employees, and our attractiveness as an investment or business partner could be negatively affected.
Similarly, our failure or perceived failure to pursue or fulfill our sustainability-focused goals, targets, and objectives, to comply
with ethical, environmental, or other standards, regulations, or expectations, or to satisfy various reporting standards with
respect to these matters, within the timelines we announce, or at all, could adversely affect our business or reputation, as well as
expose us to government enforcement actions and private litigation.
Macroeconomic and Financial Risks:
Our Debt Facilities, as defined below, contain operating and financial restrictions that may restrict our business and
financing activities.
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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;
•
•
• make investments;
•
•
• make certain acquisitions and investments;
•
•
•
•
•
•
•
•
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.
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
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:
•
•
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 methodologies and
assumptions of the administrative agent with respect to, among other things, crude oil and natural gas prices and advancement
rates for proved reserves. In November 2022, our borrowing base was reaffirmed at $775 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. Further, changes in lenders' methodologies related to
advancement rates for proved reserves could significantly affect our borrowing base. The next redetermination of our
borrowing base is scheduled to occur in spring of 2023. As of February 28, 2023, we had $543 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 85% 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.
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We have written down the carrying values on our oil and natural gas properties in the past and could incur additional
write-downs in the future.
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.
We may be adversely affected by uncertainty in the global financial markets and a worldwide economic downturn.
Our future results may be impacted by a worldwide economic downturn, continued volatility or deterioration in the debt
and equity capital markets, changes in interest rates, continued high inflation, deflation or other adverse economic conditions
that may negatively affect us or parties with whom we do business. Such circumstances may increase the credit and
performance risk associated with our purchasers, suppliers, insurers, and commodity derivative counterparties under the terms
of contracts or financial arrangements we have with them. Additionally, our assessment of these counterparty risks is hindered
by swings in the financial markets. The same circumstances may adversely impact insurers and their ability to pay current and
future insurance claims that we may have.
The global economic environment, including high inflation and continued increases in interest rates, may also adversely
impact our future access to capital. Tightening credit markets have affected, and may continue to affect, the oil and gas markets
more strongly than other industries. 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
Due to the above-listed factors, we cannot be certain that additional funding will be available if needed and, to the extent
required, on acceptable terms.
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. As of December 31, 2022, we were
over 50% hedged in both oil and gas production over the next 24 months consistent with the covenant under our Debt Facilities.
Our hedges 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
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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
28
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 under the current presidential administration. Examples of recent
environmental regulations include the following:
•
•
•
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
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.
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
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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. While the EPA rescinded parts of the 2016 regulations in 2020, they were subsequently
reinstated in July 2021. In November 2021, the EPA expanded upon the performance standards to impose more stringent
methane and volatile organic compound emission standards for new, reconstructed and modified sources in the oil and natural
gas industry and to create guidelines for existing oil and natural gas sources to be included in individual states' implementation
plans. Additionally, in December 2022, the EPA issued a supplemental proposal to further expand the standards. 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.
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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 under the current presidential administration. 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
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.
31
The Company’s operations are subject to a number of risks arising out of the threat of climate change that could
increase operating costs, limit the areas in which oil and natural gas production may occur, and reduce 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. The EPA has also proposed strict new methane emission regulations for certain oil and gas facilities.
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 have identified climate change as a priority, and it is possible 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 continue to be proposed and/or promulgated during the Biden Administration.
On August 16, 2022, President Biden signed into law the Inflation Reduction Act (the “IRA”), which, among other things,
contains tax inducements and other provisions that incentivize investment, development, and deployment of alternative energy
sources and technologies, which could increase operating costs within the oil and gas industry and accelerate the transition
away from fossil fuels. The IRA also establishes a charge on methane emissions above certain limits from the same facilities.
Additionally, 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. In August 2022, a
federal judge for the U.S. District Court of the Western District of Louisiana issued a permanent injunction against the pause of
oil and natural gas leasing on public lands or in offshore waters of the 13 plaintiff states that brought the lawsuit, which
followed a June 2021 nationwide preliminary injunction by the district court that was subsequently vacated by the U.S. Court of
Appeals for the Fifth Circuit.
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. Should we be targeted by any such litigation or investigation, we
may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed
without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.
32
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 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. For example, our exploration
and development activities and ability to transport our production to market could be adversely affected, as these events could
cause a loss of production from temporary cessation of activity or damaged facilities and equipment. If any such events were to
occur, they could have an adverse effect on our financial condition, results of operations and cash flows. 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.
On August 16, 2022, the U.S. enacted the IRA, which includes several provisions that are specifically applicable to
corporations. The IRA includes an annual 15% minimum tax on corporations that have “average annual adjusted financial
statement income” in excess of $1 billion over a three year period. The IRA also includes a 1% tax on publicly traded
corporations on the fair market value of stock repurchased during any taxable year. Such tax applies to the extent such
buybacks exceed $1 million during such year, which buyback value may be offset by other stock issuances.
Further, 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.
As of December 31, 2022, we had federal NOLs of approximately $616.1 million, approximately $274.2 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
33
(the “Code”), imposes limitations on a corporation’s ability to utilize its NOLs if it experiences an ownership change (as
determined under Section 382 of the Code). Generally, an ownership change occurs if one or more shareholders (or groups of
shareholders), each of whom is deemed to own five percent or more in value of a corporation’s stock, increase their aggregate
percentage ownership by more than 50 percent over the lowest percentage of stock owned by those shareholders at any time
during the preceding three-year period. In the event of an ownership change, utilization of the NOLs would be subject to an
annual limitation under Section 382. We believe we had an ownership change in August 2022 and, therefore, are subject to an
annual limitation on the usage of our NOLs generated prior to the ownership change. However, we do not expect to have any of
our NOLs expire before becoming available to be utilized by the Company. Management will continue to monitor the potential
impact of Section 382 with respect to our NOLs. Additional changes in our future 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:
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 18.8%, of our outstanding common
stock. SVP currently has a right to nominate two of our directors under our director nominating agreement described below.
Our current board consists of nine directors in accordance with the Bylaws, as defined below, and existing 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, a former holder of
our senior notes that provides for continuing nomination rights of two directors 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 Certificate of Incorporation, as amended, effective April 22, 2016 ( the “Charter”), and our
Second Amended and Restated Bylaws, effective October 31, 2022 (the “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:
•
•
•
•
•
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 the right to nominate up to two of our directors; and
limit the persons who may call special meetings of stockholders;
34
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 SVP, a former
holder of our senior notes that provides for continuing nomination rights of two directors subject to conditions on share
ownership.
Additionally, on September 20, 2022, the Board adopted a stockholder rights agreement, dated as of September 20, 2022,
by and between the Company and American Stock Transfer & Trust Company, LLC, as rights agent (the “Rights Agreement”),
and declared a dividend distribution of one right (each, a “Right” and together with all such rights distributed or issued pursuant
to the Rights Agreement, the “Rights”) for each outstanding share of Company common stock to holders of record on October
5, 2022. In the event that a person or group acquires beneficial ownership of 15% or more of the Company’s then-outstanding
common stock, subject to certain exceptions, each Right would entitle its holder (other than such person or members of such
group) to purchase additional shares of Company common stock at a substantial discount to the public market price. In addition,
at any time after a person or group acquires beneficial ownership of 15% or more of the outstanding common stock, subject to
certain exceptions, the Board may direct the Company to exchange the Rights (other than Rights owned by such person or
certain related parties, which will have become null and void), in whole or in part, at an exchange ratio of one share of common
stock per Right (subject to adjustment). While in effect, the Rights Agreement could make it more difficult for a third party to
acquire control of the Company or a large block of the common stock of the Company without the approval of the Board. The
Rights Agreement will expire on the earliest of (a) 5:00 p.m., New York City time, on the first business day after the 2023
annual stockholders’ meeting, (b) 5:00 p.m., New York City time, on June 30, 2023, (c) the time at which the Rights are
redeemed and (d) the time at which the Rights are exchanged in full.
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.
35
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.
Productive Well - A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from
the sale of the production exceed production expenses and taxes.
36
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
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.
37
PART II
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 104 stockholders of record as of January 31, 2023.
Stock Repurchase
There were no repurchases of the Company's common stock during the fourth quarter of 2022.
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, 2022.
38
Stock Performance Graph
The following graph compares the cumulative total return to our stockholders on our common stock beginning December
31, 2017 through December 31, 2022, relative to the cumulative returns of the Standard and Poor's 500 Index (“S&P 500”) and
the Standard and Poor's 500 Oil & Gas Exploration & Production Index (“S&P O&G E&P”) for the same period. The
comparison was prepared based upon the assumption that $100 was invested on December 31, 2017, including the reinvestment
of dividends, in each of the following: the common stock of SilverBow, the S&P 500 and the S&P O&G E&P.
39
Period EndingDollarsComparison of SilverBow Cumulative Total ReturnSilverBowS&P 500S&P 500 Oil & Gas Exploration & Production Index12/31/1712/31/1812/31/1912/31/2012/31/2112/31/22$—$50$100$150$200 Item 6. [Reserved]
40
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, 2022 and 2021, included
in this Form 10-K. The following information contains forward-looking statements; see “Forward-Looking Statements” on page
4 of this report.
The following table and discussion highlights SilverBow's drilling and completion schedule for 2022:
Operating Areas
Webb County Gas
Western Condensate
Southern Eagle Ford
Central Oil
Eastern Extension
Other (1)
Total
(1) Other includes non-core properties.
Net Acreage
2022
Production
(Mcfe/d)
Gas as % of
2022
Production
2022 Net
Wells Drilled
2022 Net
Wells
Completed
139,419
100 %
12,943
30,844
52,135
66,759
17,306
—
49,359
33,877
37,472
8,723
905
179,987
269,755
40 %
80 %
14 %
27 %
29 %
72 %
24
7
—
14
—
—
45
20
7
1
10
—
1
39
During the fourth quarter of 2022, the Company drilled 15 net wells, completed 13 net wells and brought 11 net wells
online. For the full year, SilverBow drilled 45 net wells, and completed 39 net wells and brought online 37 net wells.
SilverBow operated one drilling rig for the first six months of 2022, primarily focused on its Webb County Gas area. Then,
in conjunction with closing the Sundance acquisition on June 30, 2022, the Company added a second drilling rig and continued
operating at a two-rig drilling pace through the end of 2022. SilverBow targeted both oil and gas opportunities throughout the
second half of the year, and in the fourth quarter of 2022 operated both rigs in its Webb County Gas area. The Company
expects to remain operationally flexible going forward and will continue to optimize its drilling program in response to
commodity prices and expected returns.
In the Webb County Gas area, SilverBow drilled 24 net wells and completed and brought 20 net wells online during 2022.
The Austin Chalk formation was a key focus area of the Company's delineation and development plan, and comprised 15 of the
24 net wells drilled in the area during 2022. Well performance in the Webb County Austin Chalk continues to exceed
expectations and exhibit strong commercial economics, and during the third quarter of 2022, SilverBow completed and brought
online its best performing Austin Chalk well to date with a 30-day average production of 17 MMcf/d (100% gas). In 2022, the
Company drilled and completed multi-well pads that targeted both the Austin Chalk and Eagle Ford formations, which
supported SilverBow's expectations for high rate of return potential in full-scale development mode, and marks a progression
from the single well delineation pads targeting the Austin Chalk in prior years. Additionally, the Company focused on
expanding its Webb County and Austin Chalk position during the year with the establishment of a new acreage block within
Webb County, comprising approximately 7,500 net acres through a series of bolt-on acquisitions, leasing and drill-to-earn
agreements.
For the full year 2022, SilverBow's capital expenditures, excluding acquisitions, on an accrual basis were $327.5 million,
below the midpoint of the Company's full year guidance range of $320 to $340 million. Throughout 2022, the Company
experienced inflationary pressures on its capital and operating expenses as a result of high demand for products, materials and
services provided by vendors in conjunction with overall supply chain disruptions and tight labor market conditions. The
SilverBow team proactively took actions to mitigate the impact of these inflationary cost pressures through enhanced
procurement initiatives, pre-ordering of key materials and a focus on operational efficiencies and planning. The mid-year
increase from one drilling rig to two drilling rigs supported increased scale and achieved even better overall cycle-times. This
enhanced activity provided greater line of sight to secure available service equipment at favorable contract rates. In aggregate,
the Company's D&C costs during the year were within 1% of planned costs for the year due to the cost mitigation efforts and
operational efficiencies delivered by the team.
SilverBow closed four acquisitions in 2022. The acquired assets provide SilverBow a deep runway of future oil and gas
development locations in the Eagle Ford and Austin Chalk. The Company added more than 350 gross drilling locations from
acquired assets in 2022, with further inventory upside potential based on optimizations of well costs, spacing and lateral lengths
41
given the highly contiguous leasehold footprints with SilverBow's existing acreage. The acquisition activity in 2022 reflects a
continued focus on identifying opportunities to add to core positions in high-return areas.
For 2023, SilverBow's capital budget is expected to be in the range of $450-$475 million. The Company expects to operate
two drilling rigs throughout 2023 with approximately 90% of D&C activity directed towards oil development across its Central
Oil, Eastern Extension and Western Condensate areas. During the fourth quarter of 2022 and extending into the first quarter of
2023, SilverBow has experienced capacity constraints and higher basis differentials in Webb County. This has been driven by a
substantial increase in regional dry gas production during 2022 combined with reduced regional export capacity. Maintaining a
flexible drilling program and balanced commodity mix has been, and will continue to be, a core tenet of the Company's
business strategy, and the acquisitions made in 2021 and 2022 have significantly increased SilverBow's proved oil reserves, oil
drilling inventory and oil production base. Taken altogether, the Company expects to see the highest near-term returns from a
oil development program which is expected to drive full year 2023 oil production approximately 100% higher year-over-year
and total equivalent production approximately 25% higher year-over-year. The focus on high return oil development is
expected to also drive an increase in cash margins per Mcfe, with liquids production expected to comprise approximately 45%
of total production by year-end 2023 as compared to 28% for full year 2022. SilverBow's first quarter 2023 and full year 2023
production guidance assume that gas production from Webb County is limited to contracted firm capacity.
42
Summary of 2022 Financial Results
•
•
•
Revenues and net income (loss): The Company's oil and gas revenues were $753.4 million and $407.2 million for the years
ended December 31, 2022 and 2021, respectively. Revenues were higher due to increased production volumes and overall
higher commodity pricing. The Company had net income of $340.4 million and $86.8 million, for the years ended
December 31, 2022 and 2021, respectively. The increase in net income was primarily due to higher revenues due to
increased production volumes and higher commodity pricing.
Capital expenditures: The Company's capital expenditures (excluding acquisitions) on an accrual basis were $327.5 million
and $130.5 million for the years ended December 31, 2022 and 2021, respectively. The expenditures for the years ended
December 31, 2022 and 2021, 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 four notable acquisitions during 2022. These acquisitions, in aggregate, added 3,800
Bbls/d of liquids and 14 MMcf/d to SilverBow’s full year 2022 net production. This represents 14% of the Company's full
year 2022 net production. SilverBow expects these acquisitions to comprise a greater percentage of its full year 2023 net
production with a full year's contribution. In total the Company paid $367.0 million in cash and issued $156.3 million in
equity related to these transactions.
• Working capital: The Company had a working capital deficit of $50.1 million and $65.8 million at December 31, 2022 and
December 31, 2021, respectively. The working capital computation does not include available liquidity through our Credit
Facility.
•
Cash Flow: For the year ended December 31, 2022, the Company generated cash from operating activities of $331.2
million which included negative impacts attributable to changes in working capital of $16.0 million. Cash used for property
additions was $272.4 million and cash used in property acquisitions, including purchase price adjustments, was $367.0
million. This excluded $54.4 million attributable to a net increase of capital related payables and accrued costs. The
Company’s net borrowings under its revolving Credit Facility were $315.0 million for the year ended December 31, 2022.
For the year ended December 31, 2021, the Company generated cash from operating activities of $215.7 million, which
included negative impacts attributable to changes in working capital of $6.2 million. Cash used for property additions was
$133.6 million. This included $4.0 million attributable to a net decrease of capital related to payables and accrued costs.
The Company's net repayments under its Credit Facility were $3.0 million for the year ended December 31, 2021 and
repayments under its Second Lien Facility were $50.0 million. The Company sold shares of common stock related to our
ATM Program for net proceeds of $27.0 million for the year ended December 31, 2021.
Liquidity and Capital Resources
SilverBow's primary use of cash has been to fund capital expenditures to develop its oil and gas properties, fund
acquisitions and to re-pay Credit Facility borrowings. The Company uses cash generated from operating activities and
borrowings under its Credit Facility as its primary source of liquidity. As of December 31, 2022, SilverBow’s liquidity
consisted of approximately $0.8 million of cash-on-hand and $233.0 million in available borrowings on its Credit Facility,
which had a $775.0 million borrowing base. The Company's 2023 capital budget, which is expected to be in the range of
$450-$475 million, provides for drilling 60 gross (52 net) horizontal wells and is expected to be funded primarily from
operating cash flow. Management believes SilverBow has robust liquidity to meet all near term obligations and execute its
longer term development plans. See Note 4 to SilverBow's consolidated financial statements for more information on its Debt
Facilities.
43
Contractual Commitments and Obligations
We generally expect to fund contractual commitments with cash generated from operating activities and borrowings under
our Credit Facility. These commitments and obligations for the next five years and thereafter are shown below as of
December 31, 2022 (in thousands):
Non-cancelable operating leases
Gas transportation and processing (1)
Interest cost (2)
Long-term debt
Drilling commitments
Other contractual commitments (3)
2023
2024
2025
2026
2027
Thereafter
Total
$
8,939 $
1,913 $
934 $
779 $
51 $
488 $
13,105
2,049
1,027
785
685
624
3,724
8,894
58,422
58,494
58,574
50,032
—
—
— 692,000
8,043
4,806
2,906
10,263
—
—
—
—
—
—
—
—
—
225,521
—
692,000
—
—
15,755
10,263
Total
$ 87,716 $ 66,240 $ 63,199 $ 743,495 $
675 $
4,212 $ 965,538
(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 7.24% for the quarter ended December 31, 2022, 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) Amounts shown represent commitments for pipe inventory purchase.
Proved Oil and Gas Reserves
During 2022, our reserves increased by approximately 818.9 Bcfe due to increases in our natural gas reserves primarily
from our Webb County Gas area and contributions from acquisitions closed in 2022. As of December 31, 2022, 43% of our
total proved reserves were proved developed, compared with 46% at year-end for both 2021 and 2020.
At December 31, 2022, our proved reserves were 2,234.6 Bcfe with a Standardized Measure of $4.0 billion, which is an
increase of approximately $2.5 billion, or 159%, from the prior year-end levels. In 2022, our proved natural gas reserves
increased 570.2 Bcf, or 49%, while our proved oil reserves increased 27.9 MMBbl, or 115%, and our NGL reserves increased
13.6 MMBbl, or 71%, for a total equivalent increase of 818.9 Bcfe, or 58%.
We have added proved reserves primarily through our drilling activities and acquisitions, including 567.2 Bcfe added in
2022. 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 2022 was $6.14 per Mcf. This average price increased from the average
price of $3.75 per Mcf used for 2021. Our average oil price used in the calculation for 2022 was $94.36 per Bbl. This average
price increased from the average price of $63.98 per Bbl used in the calculation for 2021. Our average NGL price used in the
calculation for 2022 was $34.76 per Bbl. This average price increased from the average price of $25.29 per Bbl used in the
calculation for 2021.
44
Results of Operations
Revenues — Years Ended December 31, 2022 and 2021
2022 - Our oil and gas sales in 2022 increased by 85% compared to revenues in 2021, primarily due to overall higher
commodity pricing and higher production volumes. Average oil prices we received were 35% higher than those received during
2021, while natural gas prices were 44% higher and NGL prices were 15% higher.
Crude oil production was 16% and 11% of our production volumes for the years ended December 31, 2022 and 2021,
respectively, while crude oil sales revenues were 32% and 24% of oil and gas sales revenue for the years ended December 31,
2022 and 2021, respectively.
Natural gas production was 72% and 77% of our production volumes for the years ended December 31, 2022 and 2021,
respectively, while natural gas sales revenues were 60% and 66% of oil and gas sales for the years ended December 31, 2022
and 2021, respectively.
NGL production was 12% of our production volumes for each of the years ended December 31, 2022 and 2021,
respectively, while NGL sales were 8% and 10% of oil and gas sales for the years ended December 31, 2022 and 2021,
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, 2022 and 2021:
Fields
Webb County Gas
Western Condensate
Southern Eagle Ford
Central Oil
Eastern Extension
Non-Core
Total
Oil and Gas Sales (In
Millions)
2022
2021
$
325.0 $
147.9
80.2
165.4
32.8
2.1
194.6
110.7
40.8
53.7
3.8
3.6
$
753.4 $
407.2
Net Oil and Gas Production
Volumes (MMcfe)
2022
50,888
18,016
12,365
13,677
3,184
330
98,460
2021
42,955
17,922
9,858
6,300
455
623
78,113
SilverBow's sales volume increase from 2021 to 2022 was primarily due to higher production volumes across all products,
driven by full year contribution from acquisitions closed in 2021 and partial year contribution from acquisitions closed in 2022.
Additionally, the Company increased its drilling activity from 2021 to 2022, resulting in 37 net wells brought online in 2022
compared to 24 net wells brought online in 2021.
In 2022, our $346.2 million, or 85%, increase in oil, NGL, and natural gas sales resulted from:
•
•
Volume variances that had a $138.6 million favorable impact on sales, with a $79.1 million increase due to the 1.2
million Bbl increase in oil production volumes, a $46.2 million increase due to the 10.4 Bcf increase in natural gas
production volumes and a $13.3 million increase due to the 0.5 million Bbl increase in NGL production volumes.
Price variances that had a $207.7 million favorable impact on sales, with an increase of $138.0 million due to the 44%
increase in natural gas prices received, an increase of $61.6 million due to the 35% increase in oil prices received and
an increase of $8.1 million due to the 15% increase in NGL prices received.
45
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, 2022 and 2021 (in
thousands, except per-dollar amounts):
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)
Natural gas (per Mcf)
Natural gas liquids (per Bbl)
Average per Mcfe
Year Ended
December 31,
2022
Year Ended
December 31,
2021
2,634
70,958
1,950
98,460
239,247 $
451,863
62,310
753,420 $
90.84 $
6.37
31.96
7.65 $
1,462
60,510
1,472
78,113
98,607
267,687
40,906
407,200
67.46
4.42
27.78
5.21
(19.78) $
(16.50)
(2.21)
(1.88)
(2.16) $
71.06 $
4.16
30.08
5.49 $
(0.69)
(5.07)
(0.94)
50.96
3.73
22.71
4.27
$
$
$
$
$
$
$
$
(1) Oil and natural gas liquids are converted at the rate of one barrel to six Mcfe.
For the years ended December 31, 2022 and 2021 we recorded net losses of $78 million and $123 million, respectively,
related to our derivative activities. Additionally, for the year ended December 31, 2022, we recorded a net gain of $4.1 million
related to valuation changes in our 2021 and 2022 WTI Contingency Payouts (as defined in Note 9 to the Company’s
consolidated financial statements in this Form 10-K). This activity is recorded in “Net gain (loss) on commodity derivatives” on
the accompanying consolidated statements of operations in this Form 10-K. As of February 24, 2023, we had approximately
73% of total production volumes hedged for full year 2023, using the midpoint of the Company's production guidance of 325 -
345 MMcfe/d.
46
Costs and Expenses
The following table provides additional information regarding our expenses for the years ended December 31, 2022 and
2021:
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
Provision for income taxes
Year Ended
December 31, 2022
Year Ended
December 31, 2021
$
21,395 $
133,982
534
55,329
1,655
32,989
41,761
41,948
9,600
21,799
68,629
306
27,206
514
24,145
19,307
29,129
6,398
Our costs and expenses during 2022 versus 2021 were as follows:
General and Administrative Expenses, Net. These expenses on a per Mcfe basis were $0.22 and $0.28 for the years ended
December 31, 2022 and 2021, respectively. The decrease per Mcfe was due to an overall increase in production driven by our
acquisitions. Included in general and administrative expenses is $5.1 million and $4.6 million in share-based compensation for
the years ended December 31, 2022 and 2021, respectively.
Depreciation, Depletion and Amortization (“DD&A”). These expenses on a per Mcfe basis were $1.36 and $0.88 for the
years ended December 31, 2022 and 2021, respectively. The increase in our per-Mcfe depreciation, depletion and amortization
rate was primarily related to acquisitions in the second half of 2021 and first half of 2022 and inflation on future development
costs. The increase in costs is related to the increase in the per-Mcfe rate, coupled with an overall increase in production.
Lease Operating Expenses. These expenses on a per Mcfe basis were $0.58 and $0.35 for the years ended December 31,
2022 and 2021, respectively. The increase in costs is due to higher compression, labor, salt water disposal and chemical costs
driven by our acquisitions in the second half of 2021 and first half of 2022.
Transportation and gas processing. These expenses all related to natural gas and NGL sales. These expenses on a per Mcfe
basis were $0.34 and $0.31 for the years ended December 31, 2022 and 2021, respectively.
Severance and Other Taxes. These expenses on a per Mcfe basis were $0.42 and $0.25 for the years ended December 31,
2022 and 2021, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 5.5% and
4.7% for the years ended December 31, 2022 and 2021, respectively.
Interest Expense. Our gross interest expense was $41.9 million and $29.1 million for the years ended December 31, 2022
and 2021, respectively. The increase in gross interest was primarily due to higher borrowings. There was no capitalized interest
for both of the years ended December 31, 2022 and 2021.
Income Taxes. The Company recorded an income tax provision of $9.6 million for the year ended December 31, 2022
which was primarily attributable to federal and state deferred taxes of $75.8 million on income before taxes of $350.0 million,
$1.4 million of non-deductible expenses, partially offset by a benefit for the release of its $67.6 million valuation allowance. 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. During the fourth quarter of
2022, the Company's management determined there was sufficient positive evidence that indicated the Company would more
likely than not be able to fully utilize its deferred tax assets and as a result, removed the full valuation allowance of $67.6
million. 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.
47
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. Proved reserves are the estimated quantities of natural gas and condensate that geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and
operating conditions. Material revisions (upward or downward) to existing reserve estimates may occur from time to time. The
accuracy of these estimates is dependent on the quality of available data and on engineering and geological interpretation and
judgment. These inputs and assumptions all require a high degree of subjectivity and 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. 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, 2022, 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 $2.7 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.
Income taxes. Our provision for income taxes includes U.S. state and federal taxes. We record our income tax provision in
accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities
for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of
assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income
in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on
deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will
not be realized.
We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. The actual
outcome of future tax consequences could differ significantly from our estimates, which could impact our financial position,
48
results of operations and cash flows. We record adjustments to reflect actual taxes paid in the period we complete our tax
returns.
New Accounting Pronouncements. In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting
Standards Update (“ASU”) No. 2016-13, Credit Losses - Measurement of Credit Losses on Financial Instruments. The standard
changes how entities will measure credit losses for most financial assets, including accounts and notes receivables. The new
standard replaces the existing incurred loss impairment methodology with a methodology that requires consideration of a
broader range of reasonable and supportable forward-looking information to estimate all expected credit losses. The updated
guidance is effective for the Company for annual and quarterly reporting periods beginning after December 15, 2022. The
adoption of this guidance is not expected to have a material impact on the Company’s financial statements or disclosures.
In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of
Reference Rate Reform on Financial Reporting followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope
(“ASU 2021-01”), issued in January 2021. The guidance provides and clarifies optional expedients and exceptions for applying
generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or
another reference rate expected to be discontinued. The amendments within these ASUs were in effect beginning March 12,
2020, and an entity may elect to apply the amendments prospectively through December 31, 2024. As of December 31, 2022,
the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and
ASU 2021-01.
In August 2020, the FASB issued ASU No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s
Own Equity. The guidance simplifies the accounting for certain financial instruments with characteristics of liabilities and
equity, including convertible instruments and contracts in an entity’s own equity. Additionally, the amendment requires the
application of the if-converted method to calculate the impact of convertible instruments on diluted earnings per share (EPS).
The guidance is effective for the Company for fiscal years beginning after December 15, 2022. The adoption of this guidance is
not expected to have a material impact on the Company’s financial statements or disclosures.
49
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, 2022, approximately 22%, 11%, 14% and 12% of our oil
and gas receipts were accounted for by Kinder Morgan, Inc. (“Kinder Morgan”), Plains Marketing, LP (“Plains Marketing”),
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, 2022, we had a combined $692.0 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 Debt Facilities at December 31, 2022 would increase our annual interest expense by $6.9 million.
50
Item 8. Financial Statements and Supplementary Data
Page
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
52
53
54
56
57
58
59
60
85
51
Management's Report on Internal Control Over Financial Reporting
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, 2022. 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, 2022. BDO USA, LLP, our independent registered public accounting firm, has
independently audited 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.
52
Report of Independent Registered Public Accounting Firm
Stockholders and Board of Directors
SilverBow Resources, Inc.
Houston, Texas
Opinion on Internal Control over Financial Reporting
We have audited SilverBow Resources, Inc.’s (the “Company’s”) internal control over financial reporting as of December
31, 2022, 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, 2022, 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, 2022 and 2021, 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 2, 2023 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 2, 2023
53
Report of Independent Registered Public Accounting Firm
Stockholders and Board of Directors
SilverBow Resources, Inc.
Houston, Texas
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of SilverBow Resources, Inc. (the “Company”) as of
December 31, 2022 and 2021, 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,
2022 and 2021, 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, 2022, 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 2, 2023 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”).
54
We have identified the estimation and timing 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. These
inputs and assumptions all require a high degree of subjectivity and 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, 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, and reading the report prepared by the independent petroleum
engineers and geologists.
Comparing estimated production volumes and production decline analyses for certain fields against results of actual
production volumes 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 for certain fields 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 and ability 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 2, 2023
55
Consolidated Balance Sheets
SilverBow Resources, Inc. (in thousands, except share amounts)
December 31, 2022 December 31, 2021
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 $16,272 and $17,090
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:
$
792 $
$
$
89,714
52,549
2,671
145,726
2,529,223
(1,004,044)
1,525,179
12,077
24,172
9,208
1,716,362 $
60,200 $
40,796
56,465
2,665
8,553
27,160
195,839
688,531
3,775
16,141
9,171
7,738
3,588
1,121
49,777
2,806
1,875
55,579
1,611,953
(869,985)
741,968
16,065
201
5,641
819,454
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
Preferred stock, $0.01 par value, 10,000,000 shares authorized, none issued
—
—
Common stock, $0.01 par value, 40,000,000 shares authorized, 22,663,135
and 16,822,845 shares issued, respectively, and 22,309,740 and 16,631,175
shares outstanding, respectively
Additional paid-in capital
Treasury stock held, at cost, 353,395 and 191,670 shares, respectively
Retained earnings (Accumulated deficit)
Total Stockholders’ Equity
Total Liabilities and Stockholders’ Equity
$
See accompanying Notes to Consolidated Financial Statements.
227
576,118
(7,534)
222,768
791,579
1,716,362 $
168
413,017
(2,984)
(117,669)
292,532
819,454
56
Year Ended December 31,
2022
2021
$
753,420 $
407,200
21,395
133,982
534
55,329
1,655
32,989
41,761
21,799
68,629
306
27,206
514
24,145
19,307
287,645
161,906
465,775
245,294
(73,885)
(41,948)
95
(123,018)
(29,129)
10
350,037
93,157
9,600
6,398
$
340,437 $
86,759
$
$
17.24 $
6.61
16.94 $
6.42
19,748
13,118
20,097
13,520
Consolidated Statements of Operations
SilverBow Resources, Inc. (in thousands, except per-share amounts)
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
Total Operating Expenses
Operating Income (Loss)
Non-Operating Income (Expense)
Net gain (loss) on commodity derivatives
Interest expense, net
Other income (expense), net
Income (Loss) Before Income Taxes
Provision (Benefit) for Income Taxes
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.
57
Consolidated Statements of Stockholders’ Equity
SilverBow Resources, Inc. (in thousands, except share amounts)
Common
Stock
Additional
Paid-in
Capital
Treasury
Stock
Retained
Earnings
(Accumulated
Deficit)
Total
Balance, December 31, 2020
$
121 $ 297,712 $
(2,372) $
(204,428) $ 91,033
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
Shares issued from option exercise (15,584 shares)
Purchase of treasury shares (120,350 shares)
Treasury shares pursuant to purchase price adjustment (41,375 shares)
Vesting of share-based compensation (375,745 shares)
Issuance pursuant to acquisitions (5,448,961 shares)
Share-based compensation
Net Income
Balance, December 31, 2022
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
—
—
—
4
55
—
—
426
—
—
(4)
157,350
5,329
—
—
(3,397)
(1,153)
—
—
—
—
—
—
—
—
—
—
426
(3,397)
(1,153)
—
157,405
5,329
340,437
340,437
$
227 $ 576,118 $
(7,534) $
222,768 $ 791,579
58
Consolidated Statements of Cash Flows
SilverBow Resources, Inc. (in thousands)
Cash Flows from Operating Activities:
Net income
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating
activities-
Depreciation, depletion, and amortization
Accretion of asset retirement obligations
Deferred income tax expense (benefit)
Share-based compensation expense
(Gain) Loss on commodity 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
Net Cash Provided by (Used in) Operating Activities
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
Net proceeds from stock options exercised
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
Cash, Cash Equivalents at Beginning of Year
Cash, Cash Equivalents 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.
59
Year Ended
December 31,
2022
Year Ended
December 31,
2021
$
340,437 $
86,759
133,982
534
9,625
5,086
73,885
(219,626)
(48)
350
3,010
(29,522)
11,788
(229)
1,969
331,241
(272,443)
(367,024)
4,347
(750)
(635,870)
—
841,000
(526,000)
—
39
(3,397)
(7,342)
304,300
(329)
1,121
792 $
36,994 $
54,372 $
(156,252) $
68,629
306
6,212
4,645
123,018
(70,582)
(158)
229
2,877
(23,513)
17,507
83
(286)
215,726
(133,638)
(51,734)
—
(1,084)
(186,456)
(50,000)
335,000
(338,000)
26,956
—
(612)
(3,611)
(30,267)
(997)
2,118
1,121
27,221
(4,033)
(83,522)
$
$
$
$
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.
Stockholder Rights Agreement. On September 20, 2022, the Board adopted a stockholder rights agreement, dated as of
September 20, 2022, by and between the Company and American Stock Transfer & Trust Company, LLC, as rights agent (the
“Rights Agreement”), and declared a dividend distribution of one right (each, a “Right” and together with all such rights
distributed or issued pursuant to the Rights Agreement, the “Rights”) for each outstanding share of Company common stock to
holders of record on October 5, 2022. In the event that a person or group acquires beneficial ownership of 15% or more of the
Company’s then-outstanding common stock, subject to certain exceptions, each Right would entitle its holder (other than such
person or members of such group) to purchase additional shares of Company common stock at a substantial discount to the
public market price. In addition, at any time after a person or group acquires beneficial ownership of 15% or more of the
outstanding common stock, subject to certain exceptions, the Board may direct the Company to exchange the Rights (other than
Rights owned by such person or certain related parties, which will have become null and void), in whole or in part, at an
exchange ratio of one share of common stock per Right (subject to adjustment). While in effect, the Rights Agreement could
make it more difficult for a third party to acquire control of the Company or a large block of the common stock of the Company
without the approval of the Board. The Rights Agreement will expire on the earliest of (a) 5:00 p.m., New York City time, on
the first business day after the 2023 annual stockholders’ meeting, (b) 5:00 p.m., New York City time, on June 30, 2023, (c) the
time at which the Rights are redeemed and (d) the time at which the Rights are exchanged in full.
Subsequent Events. We have evaluated subsequent events requiring potential accrual or disclosure in our consolidated
financial statements.
Through February 24, 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, 2022:
Natural Gas Basis Derivative Swaps
(East Texas Houston Ship Channel vs. NYMEX Settlements)
Total Volumes
(MMBtu)
Weighted
Average Price
Calendar Monthly Roll Differential Swaps
2023 Contracts
1Q23
2Q23
3Q23
4Q23
2024 Contracts
1Q24
2Q24
3Q24
4Q24
1,460,000 $
1,820,000 $
1,840,000 $
920,000 $
1,820,000 $
1,820,000 $
1,840,000 $
1,840,000 $
(0.37)
(0.37)
(0.27)
(0.38)
(0.14)
(0.35)
(0.29)
(0.51)
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
60
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, 2022 and 2021, such internal costs when capitalized totaled $4.3 million and $4.8 million,
respectively. There was no capitalized interest on our unproved properties for both the years ended December 31, 2022 and
2021.
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,
2022
December 31,
2021
$
2,506,853 $
1,588,978
16,272
6,098
(1,004,044)
1,525,179 $
$
17,090
5,885
(869,985)
741,968
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
61
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
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 business combinations 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 either of the years ended December 31, 2022
and 2021.
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
62
natural gas properties will occur 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, 2022 and 2021 (in thousands):
Oil, natural gas and NGLs sales:
Oil
Natural gas
NGLs
Total
Year Ended
December 31, 2022
Year Ended
December 31, 2021
$
$
239,247 $
451,863
62,310
753,420 $
98,607
267,687
40,906
407,200
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, 2022 and 2021, 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, 2022, our “Accounts receivable, net” balance included $70.9 million for oil and gas sales, $5.6 million
due from joint interest owners, $4.3 million for severance tax credit receivables and $8.9 million for other receivables. At
December 31, 2021, our “Accounts receivable, net” balance included $45.3 million for oil and gas sales, $1.9 million for joint
interest owners, $1.0 million for severance tax credit receivables and $1.5 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, 2022 and 2021 did not exceed our actual costs incurred. The total amount of supervision
fees charged to the wells we operated was $8.8 million and $5.1 million for the years ended December 31, 2022 and 2021,
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, 2022, 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. 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. We continually monitor all positive and negative evidence related to our determination on the need for a
valuation allowance. During the fourth quarter of 2022, the Company's overall deferred tax position moved from a net deferred
63
tax asset position into a net deferred tax liability position, exclusive of a valuation allowance. In addition, the Company now
believes it has a significant history of earnings over the prior three years and also considered the scheduled reversal of deferred
tax liabilities (including the impact of available carryback and carryforward periods) and projected future taxable income in
making this assessment. As such, during the fourth quarter of 2022, the Company's management determined there was
sufficient positive evidence that indicated the Company would more likely that not be able to fully utilize its deferred tax assets
and as a result, removed the full valuation allowance. Our effective tax rate for 2022 differs from the statutory rate primarily
due to the removal of the full valuation allowance. We recorded an income tax provision of $9.6 million which was primarily
attributable to deferred federal and state income tax expense of $75.8 million on income before taxes of $350.0 million,
$1.4 million of non-deductible expenses, partially offset by a benefit for the release of the $67.6 million valuation allowance,
offset by a benefit for the release of the valuation allowance for the year ended December 31, 2022. While the Company
expects to realize the deferred tax assets, changes in future taxable income or in tax laws may alter this expectation and result in
future increases to the valuation allowance.
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,
2022
December 31,
2021
$
$
23,660 $
10,572
4,814
1,284
4,849
1,988
13,033
60,200 $
9,688
4,192
7,029
524
3,314
1,972
8,315
35,034
(1) Included in Other Payables is $6.0 million and $6.4 million in payables for settled derivatives for the years ended December 31, 2022 and 2021,
respectively.
Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to
be cash equivalents.
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, 2022 and 2021, 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, 2022
Year Ended
December 31, 2021
22 %
11 %
*
14 %
12 %
26 %
10 %
15 %
16 %
12 %
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, 2022 and 2021, we purchased 120,350 and
74,586 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. Additionally, for the
year ended December 31, 2022, we received 41,375 shares in conjunction with our post-closing settlement for a previous
acquisition.
64
New Accounting Pronouncements. In June 2016, the Financial Accounting Standards Board (“FASB”) issued
Accounting Standards Update (“ASU”) No. 2016-13 , Credit Losses - Measurement of Credit Losses on Financial Instruments.
The standard changes how entities will measure credit losses for most financial assets, including accounts and notes receivables.
The new standard replaces the existing incurred loss impairment methodology with a methodology that requires consideration
of a broader range of reasonable and supportable forward-looking information to estimate all expected credit losses. The
updated guidance is effective for the Company for annual and quarterly reporting periods beginning after December 15, 2022.
The adoption of this guidance is not expected to have a material impact on the Company’s financial statements or disclosures.
In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of
Reference Rate Reform on Financial Reporting followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope
(“ASU 2021-01”), issued in January 2021. The guidance provides and clarifies optional expedients and exceptions for applying
generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or
another reference rate expected to be discontinued. The amendments within these ASUs were in effect beginning March 12,
2020, and an entity may elect to apply the amendments prospectively through December 31, 2024. As of December 31, 2022,
the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and
ASU 2021-01.
In August 2020, the FASB issued ASU No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s
Own Equity. The guidance simplifies the accounting for certain financial instruments with characteristics of liabilities and
equity, including convertible instruments and contracts in an entity’s own equity. Additionally, the amendment requires the
application of the if-converted method to calculate the impact of convertible instruments on diluted earnings per share (EPS).
The guidance is effective for the Company for fiscal years beginning after December 15, 2022. The adoption of this guidance is
not expected to have a material impact on the Company’s 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. There were no shares of common stock sold under the ATM Program during the year ended
December 31, 2022.
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.
65
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, 2022
Year Ended December 31, 2021
Net Income
(Loss)
Shares
Per Share
Amount
Net Income
(Loss)
Shares
Per Share
Amount
Basic EPS:
Net Income (Loss) and
Share Amounts
Dilutive Securities:
Restricted Stock Unit
Awards
Performance Based Stock
Unit Awards
Stock Option Awards
$
340,437
19,748 $
17.24 $
86,759
13,118 $
6.61
162
149
38
285
117
—
Diluted EPS:
Net Income (Loss) and
Assumed Share Conversions $
340,437
20,097 $
16.94 $
86,759
13,520 $
6.42
Less than 0.1 million and 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS
for both the years ended December 31, 2022 and 2021, because they were antidilutive.
Less than 0.1 million shares of restricted stock units were not included in the computation of Diluted EPS for the year
ended December 31, 2022 because they were antidilutive. There were no antidilutive shares of restricted stock units for the year
ended December 31, 2021.
There were no antidilutive shares of performance-based restricted stock units for either of the years ended December 31,
2022 and 2021.
3. Provision (Benefit) for Income Taxes
Income (Loss) before taxes is as follows (in thousands):
Income (Loss) Before Income Taxes
Year Ended
December 31, 2022
Year Ended
December 31, 2021
$
350,037 $
93,157
The following is an analysis of the consolidated income tax provision (benefit) (in thousands):
Current:
Federal
State
Total current income tax provision (benefit)
Deferred:
Federal
State
Total deferred income tax provision (benefit)
Total tax expenses
Year Ended
December 31, 2022
Year Ended
December 31, 2021
$
$
$
— $
(25)
(25)
7,188
2,437
9,625 $
9,600 $
—
186
186
5,500
712
6,212
6,398
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Our effective tax rate for 2022 differs from the statutory rate primarily due to the removal of the full valuation allowance
during the fourth quarter of 2022. 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, 2022
Year Ended
December 31, 2021
21.0 %
0.7 %
0.4 %
(0.1) %
(19.3) %
2.7 %
21.0 %
1.0 %
0.6 %
0.6 %
(16.2) %
6.9 %
The tax effects of temporary differences representing the net deferred tax asset (liability) at December 31, 2022 and 2021
were as follows (in thousands):
Deferred tax assets:
December 31, 2022 December 31, 2021
Federal net operating loss (“NOL”) carryovers
$
130,296 $
97,142
Other carryover items
Asset retirement obligations
Share-based compensation
Lease liability
Interest
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)
649
2,258
439
2,589
8,798
—
963
—
145,992 $
(141,771) $
(16,943)
(2,536)
(883)
(162,133)
(16,141) $
(3,453) $
(12,688)
(16,141) $
$
$
$
$
$
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)
The Company’s valuation allowance balance was $67.6 million at December 31, 2021. There was no valuation allowance
at December 31, 2022.
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 $346.2 million generated from 2018 through 2022. The losses generated
between 2013 and 2017 will expire between 2033 and 2037 if not utilized. The losses generated from 2018 through 2022 will
not expire under the current tax code, but their usage will be limited to 80% of taxable income. We experienced an ownership
change within the meaning of Section 382 during 2022 and our annual usage of losses up to the change date in 2022 may be
limited; however, at this time, we do no expect any of the losses to expire unused. We generated approximately $151.0 million
in NOL carryforward assets in 2022, of which, $53.4 million relates to the time period post ownership change within the
meaning of Section 382 and is not subject to limitation. Should we experience another ownership change within the meaning of
Section 382, our NOLs could be further limited.
67
Our U.S. federal and most state income tax returns from 2019 forward are subject to examination. For years prior to 2019
our U.S. federal returns are subject to examination to the extent of our net operating loss (NOL) carryforwards. Our Texas tax
returns from 2018 forward are subject to examination. There are no material unresolved items related to periods previously
audited by the taxing authorities. On August 15, 2022, President Biden signed the Inflation Reduction Act into law.
Management has reviewed the tax provisions of this legislation and has determined that there are no provisions that would have
a material impact on the Company.
4. Long-Term Debt
The Company's long-term debt consisted of the following (in thousands):
Credit Facility Borrowings due 2026 (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, 2022 December 31, 2021
$
542,000 $
150,000
692,000
(882)
(2,587)
$
688,531 $
227,000
150,000
377,000
(1,061)
(3,114)
372,825
(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, 2022 and 2021, we had $8.7 million and $3.6 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.
Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $542.0 million and
$227.0 million as of December 31, 2022 and 2021, 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 an unscheduled redetermination of the borrowing base requested by SilverBow along
with its administrative agent as part of the SandPoint (as defined later) and Sundance asset acquisitions in the second quarter of
2022, the Company entered into the Tenth Amendment to the Credit Facility, effective June 22, 2022 (the “Tenth
Amendment”), which among other things, increased the borrowing base under the Credit Facility to $775.0 million from
$525.0 million, effective upon the closing of the Sundance acquisition on June 30, 2022; extended the maturity date for the
Credit Agreement to October 19, 2026 (or to the extent earlier, the date that is 91 days prior to the scheduled maturity of the
Company's Second Lien notes); increased the maximum credit amounts from $1.0 billion to $2.0 billion; decreased the
applicable margin used to calculate the interest rate under the Credit Facility by 50 basis points, with the specific applicable
margins determined by reference to borrowing base utilization; decreased the mortgage coverage and title requirements from
90% to 85%; amended the restricted payment basket allowing the Company to make dividends or other distribution or return of
capital to the extent that the Company's total leverage does not exceed 1.25x and the utilization percentage as of the date of
such dividend or distribution is less than 80% after giving effect to such restricted payment; and added two new lenders as
parties to the Credit Agreement. Earlier in the second quarter of 2022, the Company entered into the Ninth Amendment to the
Credit Facility, effective April 12, 2022, as part of the regular, semi-annual redetermination. Prior to the Tenth Amendment, the
Ninth Amendment had previously, among other things, increased the borrowing base under the Credit Agreement from
$460 million to $525 million. In conjunction with its regularly scheduled semi-annual redetermination, the Company reaffirmed
the borrowing base and elected commitment amount under the Credit Facility at $775.0 million, effective November 22, 2022.
Effective upon the execution of the Tenth Amendment on June 22, 2022, the Credit Facility matures October 19, 2026 (or
to the extent earlier, the date that is 91 days prior to the scheduled maturity of the Company's Second Lien notes), and provides
for a maximum credit amount of $2.0 billion, subject to the current borrowing base of $775.0 million. 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, 2022 and 2021. 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.
68
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 upon the execution
of the Tenth Amendment on June 22, 2022, the applicable margin decreased by 50 basis points and ranged from 1.75% to
2.75% based on borrowing base utilization for ABR Loans and 2.75% to 3.75% based on borrowing base utilization 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. As of December 31, 2022, the Company's weighted average
interest rate on Credit Facility borrowings was 7.60%.
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
85% of estimated proved reserves of the Company and its subsidiary effective upon the execution of the Tenth Amendment on
June 22, 2022.
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 3.00 to 1.0 as of the last day of each
fiscal quarter; 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, 2022, 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
$26.9 million and $11.3 million for the years ended December 31, 2022 and 2021, respectively. The amount of commitment fee
amortization included in interest expense, net was $1.2 million and $0.5 million for the years ended December 31, 2022 and
2021, 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
69
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 at 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 3.25 to 1.0 as of the last day of each
fiscal quarter. As of December 31, 2022, 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.
As of December 31, 2022, net amounts recorded for the Second Lien Notes were $146.5 million, net of unamortized debt
discount and debt issuance costs. Interest expense on the Second Lien totaled $15.0 million and $17.8 million for the years
ended December 31, 2022 and 2021, 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. During the years ended December 31, 2022 and 2021, the Company capitalized $7.3 million and
$3.6 million, respectively, for debt issuance costs incurred in connection with the amendments to our Credit Facility.
Additionally, the Company wrote-off $0.4 million and $0.2 million in debt issuance costs during the years ended December 31,
2022 and 2021, respectively, related to changes under our Credit Facility.
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.
70
During the years ended December 31, 2022 and 2021, the Company recorded losses of $78.0 million and $123.0 million,
respectively, relating to our commodity derivative activities. The Company made net cash payments of $219.6 million and
$70.6 million for settled derivative contracts during the years ended December 31, 2022 and 2021, respectively. During the year
ended December 31, 2022, the Company recorded gains of $4.1 million related to valuation changes on the 2021 and 2022 WTI
(“West Texas Intermediate”) Contingency Payouts.
At December 31, 2022 and 2021, we had $6.9 million and $0.9 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 2023 and 2022, respectively. At December 31, 2022 and 2021, we also had $6.0 million and $6.4 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 2023 and 2022, 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, 2022 there was $52.5 million and $24.2 million in current unsettled
derivative assets and long-term unsettled derivative assets, respectively, and $40.8 million and $7.7 million in current unsettled
derivative liabilities and long-term unsettled derivative liabilities, respectively. At December 31, 2021, the Company had $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.
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 $28.2 million net fair value asset at December 31, 2022 and $53.0
million net fair value liability at December 31, 2021. For further discussion related to the fair value of the Company's
derivatives, refer to Note 10 of these Notes to Consolidated Financial Statements.
71
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, 2022.
Oil Derivative Swaps
(New York Mercantile Exchange (“NYMEX”)
WTI Settlements)
Total
Volumes
(Bbls)
Weighted
Average
Price
Weighted
Average
Collar Sub
Floor Price
Weighted
Average
Collar
Floor Price
Weighted
Average
Collar Call
Price
Swap Contracts
2023 Contracts
1Q23
2Q23
3Q23
4Q23
2024 Contracts
1Q24
2Q24
3Q24
4Q24
Collar Contracts
2023 Contracts
1Q23
2Q23
3Q23
4Q23
2024 Contracts
1Q24
2Q24
3-Way Collar Contracts
2023 Contracts
1Q23
2Q23
3Q23
4Q23
2024 Contracts
1Q24
2Q24
$
$
$
$
$
$
47.37 $
53.91 $
59.27 $
58.54 $
66.00
64.89
66.26
65.13
51.61 $
45.00 $
65.86
60.72
$
$
$
$
$
$
44.24 $
55.14 $
44.19 $
55.04 $
43.08 $
53.41 $
43.08 $
53.38 $
64.55
64.53
63.33
63.35
45.00 $
57.50 $
45.00 $
57.50 $
67.85
67.85
532,175 $
494,575 $
533,980 $
569,300 $
227,500 $
249,500 $
229,000 $
217,000 $
81.52
80.75
77.36
78.26
80.78
80.47
78.90
77.76
171,707
167,949
72,847
72,242
137,700
33,000
14,470
13,260
9,570
8,970
8,247
7,757
72
Natural Gas Derivative Swaps
(NYMEX Henry Hub Settlements)
Total
Volumes
(MMBtu)
Weighted
Average
Price
Weighted
Average
Collar Sub
Floor Price
Weighted
Average
Collar
Floor Price
Weighted
Average
Collar Call
Price
Swap Contracts
2023 Contracts
1Q23
2Q23
3Q23
4Q23
2024 Contracts
1Q24
2Q24
3Q24
4Q24
2025 Contracts
1Q25
2Q25
3Q25
4Q25
Collar Contracts
2023 Contracts
1Q23
2Q23
3Q23
4Q23
2024 Contracts
1Q24
2Q24
3Q24
4Q24
3-Way Collar Contracts
2023 Contracts
1Q23
2Q23
3Q23
4Q23
2024 Contracts
1Q24
2Q24
981,000 $
3,816,000 $
4,816,000 $
3,887,000 $
2,711,000 $
7,800,000 $
7,820,000 $
7,820,000 $
900,000 $
910,000 $
920,000 $
920,000 $
6.74
4.55
4.57
4.71
5.15
3.95
4.03
4.35
5.01
4.12
4.27
4.70
13,967,900
12,141,250
11,896,400
12,445,000
7,841,000
2,823,000
2,958,000
2,945,000
347,800
310,400
233,100
219,200
198,000
188,000
73
$
$
$
$
$
$
$
$
2.06 $
2.04 $
2.00 $
2.00 $
3.86 $
3.28 $
3.43 $
3.87 $
4.10 $
4.05 $
4.00 $
4.24 $
2.56 $
2.54 $
2.50 $
2.50 $
2.00 $
2.00 $
2.50 $
2.50 $
5.50
4.05
4.23
4.80
6.19
4.91
5.10
5.63
3.03
3.01
2.95
2.94
3.37
3.37
$
$
$
$
$
$
Natural Gas Basis Derivative Swaps
(East Texas Houston Ship Channel vs. NYMEX Settlements)
Total Volumes
(MMBtu)
Weighted
Average Price
2023 Contracts
1Q23
2Q23
3Q23
4Q23
2024 Contracts
1Q24
2Q24
3Q24
4Q24
Houston Ship Channel Fixed Price Contracts
2023 Contracts
1Q23
2Q23
NGL Swaps (Mont Belvieu)
2023 Contracts
1Q23
2Q23
3Q23
4Q23
2024 Contracts
1Q24
2Q24
3Q24
4Q24
12,600,000 $
12,740,000 $
12,880,000 $
12,880,000 $
6,370,000 $
6,370,000 $
6,440,000 $
6,440,000 $
0.05
(0.23)
(0.20)
(0.22)
0.03
(0.31)
(0.27)
(0.24)
180,000 $
60,000 $
2.64
2.64
Total Volumes
(Bbls)
Weighted-
Average Price
337,500 $
341,250 $
345,000 $
345,000 $
127,400 $
127,400 $
128,800 $
128,800 $
33.12
33.12
32.87
32.87
29.39
29.39
29.39
29.39
6. Commitments and Contingencies
We have gas transportation and processing minimum obligations amounting to $2.0 million for 2023, $1.0 million for
2024, $0.8 million for 2025, $0.7 million for 2026 and $8.9 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, 2022.
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
$1.5 million for the year ended December 31, 2022. Additionally, we have drilling commitments amounting to $8.0 million for
2023, $4.8 million for 2024 and $2.9 million for 2025.
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
74
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 $5.1 million and $4.6 million for the years ended
December 31, 2022 and 2021, respectively. Capitalized share-based compensation was $0.2 million and for both the years
ended December 31, 2022 and 2021.
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 140,446 at December 31, 2022.
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, 2022, we had no unrecognized compensation cost related to stock option awards. The following table
represents stock option award activity for the year ended December 31, 2022:
Options outstanding, beginning of period
Options exercised
Options expired
Options outstanding, end of period
Options exercisable, end of period
Shares
Wtd. Avg.
Exer. Price
28.12
26.96
33.48
26.46
26.46
276,009 $
(15,584) $
(64,263) $
196,162 $
196,162 $
Our outstanding stock option awards at December 31, 2022 had $0.4 million measurable aggregate intrinsic value. At
December 31, 2022 the weighted-average remaining contract life of stock option awards outstanding was 4.4 years and
exercisable was 4.4 years. The stock option awards exercisable as of December 31, 2022 had $0.4 million in 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, 2022, we had unrecognized compensation expense of $2.8 million related to our restricted stock units
which is expected to be recognized over a weighted-average period of 2.1 years.
75
The following table provides information regarding restricted stock unit activity for the year ended December 31, 2022:
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
8.60
26.00
18.55
8.86
21.18
344,845 $
179,416 $
(19,214) $
(277,933) $
227,114 $
On May 21, 2019, the Company granted 99,500 PSUs 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, 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. 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. In the first quarter of 2023, the Board and its Compensation Committee approved
payout of these awards at 188% of target. Accordingly, 303,410 shares were issued on February 22, 2023.
On February 23, 2022, the Company granted 122,111 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, 2022 to
December 31, 2024. 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 $36.47 per unit or 150.93% 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. All PSUs granted remain outstanding related to this award as of December 31, 2022.
As of December 31, 2022, we had unrecognized compensation expense of $3.1 million related to our performance-based
stock units based on the assumption of 100.0% target payout. The remaining weighted-average performance period is 2.0 years.
The following table provides information regarding performance-based stock unit activity for the year ended December 31,
2022:
Shares
Wtd. Avg.
Grant Price
18.84
36.47
18.86
18.86
23.18
244,989 $
122,111 $
14,212 $
(97,812) $
283,500 $
Performance based stock units outstanding, beginning of period
Performance based stock units granted
Performance based stock units incremental shares granted
Performance based stock units vested
Performance based stock units outstanding, end of period
Employee Savings Plan
76
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
2022 and 2021. The Company's plan contributions of $0.6 million and $0.5 million for the years ended December 31, 2022 and
2021, 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. The
Company elected for 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 represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are
classified as follows (in thousands):
Lease Costs Included in the Asset Additions in the 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 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, 2022
Year Ended
December 31, 2021
$
$
15,219 $
—
15,219 $
3,472
—
3,472
Year Ended
December 31, 2022
Year Ended
December 31, 2021
$
$
6,275 $
8,304
754
15,333 $
1,873
5,325
844
8,042
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,
2022
As of December 31,
2021
2.5
4.6 %
3.0
4.1 %
77
As of December 31, 2022, the Company's future undiscounted cash payment obligation for its operating lease liabilities are
as follows (in thousands):
As of December 31, 2022
2023
2024
2025
2026
2027
Thereafter
Total undiscounted lease payments
Present value adjustment
Net operating lease liabilities
$
$
$
8,939
1,913
934
779
51
488
13,104
(776)
12,328
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
Non-cash Investing and Financing Activities
Additions to ROU assets obtained from new operating lease liabilities
Year Ended
December 31, 2022
Year Ended
December 31, 2021
$
$
9,052 $
5,342 $
6,011
8,779
Rental and lease expense was $14.6 million and $7.0 million for the years ended December 31, 2022 and 2021,
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 on May 18, 2021. As of December 31, 2022, the minimum contractual obligations were approximately $3.0
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, $0.8 million and $1.1 million was paid during the years ended December 31,
2022 and 2021, respectively. There is no remaining obligation under this contract as of December 31, 2022.
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.
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
78
the relative fair value of the assets acquired and liabilities assumed. As part of the post-closing settlement of this acquisition,
during the year ended December 31, 2022 we issued 489 new shares and received 41,375 shares back into treasury stock.
November 2021 Acquisition
On November 19, 2021, the Company closed on an acquisition of oil-weighted assets in the Eagle Ford. 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 (the “2021 WTI Contingency Payout”). During the year ended December 31,
2022, the Company recorded losses of $1.2 million, related to the 2021 WTI Contingency Payout recorded in “Gain (loss) on
commodity derivatives, net” on the consolidated statements of operation and recorded $1.6 million in earn-out consideration
payable to the seller related to the 2022 calendar year in “Accounts payable and accrued liabilities” on the consolidated balance
sheets. 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. 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.
May 2022 Acquisition
On May 10, 2022, the Company closed the acquisition of certain oil and gas assets located in La Salle and McMullen
Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date, from SandPoint
Operating, LLC, a subsidiary of SandPoint Resources, LLC (collectively, “SandPoint”). After consideration of closing
adjustments, total aggregate consideration was approximately $67.5 million, consisting of $27.7 million in cash and 1,300,000
shares of our common stock valued at approximately $39.8 million based on the Company's share price on the closing date. We
incurred approximately $0.5 million in transaction costs during the year ended December 31, 2022 related to the acquisition.
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.
79
The following table represents the allocation of the total cost of the transaction to the assets acquired and liabilities
assumed (in thousands):
Total Cost
Cash consideration
Equity consideration
Total Consideration
Transaction costs
Total Cost of Transaction
Allocation of Total Cost
Assets
Oil and gas properties
Total assets
Liabilities
Accounts payable and accrued liabilities
Fair value of commodity derivatives
Asset retirement obligations
Total Liabilities
Net Assets Acquired
$
$
$
$
$
27,709
39,767
67,476
466
67,942
84,810
84,810
199
16,511
158
16,868
67,942
June 2022 Acquisition
On June 30, 2022, the Company closed the acquisition of certain oil and gas assets located in Atascosa, La Salle, Live Oak
and McMullen Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date,
from Sundance Energy, Inc., and its affiliated entities Armadillo E&P, Inc. and SEA Eagle Ford, LLC (collectively,
“Sundance”). After consideration of closing adjustments, total aggregate consideration was approximately $344.9 million,
consisting of $220.9 million in cash, 4,148,472 shares of our common stock valued at approximately $117.7 million based on
the Company's share price on the closing date, accrued purchase price adjustments receivable of $1.0 million and contingent
consideration with an estimated fair value of $7.4 million. The contingent consideration consists of up to two earn-out payments
of $7.5 million each, contingent upon the average monthly settlement price of NYMEX West Texas Intermediate crude oil
exceeding $95 per barrel for the period from April 13, 2022 through December 31, 2022 which would trigger a payment of
$7.5 million in 2023 and $85 per barrel for 2023 which would trigger a payment of $7.5 million in 2024 (the “2022 WTI
Contingency Payout”). The contingent payout for the period of April 13, 2022 through December 31, 2022 did not materialize.
During the year ended December 31, 2022, the Company recorded gains of $5.3 million related to the 2022 WTI Contingency
Payout recorded in “Gain (loss) on commodity derivatives, net” on the accompanying consolidated statements of operations.
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 $6.8 million in transaction costs during the year ended December 31, 2022 related to the acquisition.
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.
80
The following table represents the allocation of the total cost of the transaction to the assets acquired and liabilities
assumed (in thousands):
Total Cost
Cash consideration
Equity consideration
Fair value of contingent consideration
Accrued purchase price adjustments receivable
Total Consideration
Transaction costs
Total Cost of Transaction
Allocation of Total Cost
Assets
Other current assets
Oil and gas properties
Right of use assets
Total assets
Liabilities
Accounts payable and accrued liabilities
Fair value of commodity derivatives
Non-current lease liability
Asset retirement obligations
Total Liabilities
Net Assets Acquired
$
$
$
$
$
220,866
117,651
7,422
(1,000)
344,939
6,766
351,705
4,202
397,401
890
402,493
13,687
33,767
890
2,444
50,788
351,705
August 2022 Acquisition
On August 15, 2022, the Company closed the acquisition of certain oil and gas assets in Webb County, Texas. After
consideration of closing adjustments, total consideration was approximately $31.2 million. We did not incur any significant
transaction costs during the year ended December 31, 2022 related to the acquisition. 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.
October 2022 Acquisition
On October 31, 2022, the Company closed the acquisition of certain oil and gas assets in Dewitt and Gonzales Counties,
Texas. After consideration of closing adjustments, total consideration was approximately $80.1 million. The acquisition is
subject to further customary post-closing adjustments. We did not incur any significant transaction costs during the year ended
December 31, 2022 related to the acquisition. 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.
2022 Non-strategic Dispositions
During 2022, the Company closed on multiple dispositions of non-strategic oil and gas assets. After consideration of
closing adjustments, total proceeds from the dispositions were approximately $4.3 million. There was no gain or loss
recognized in connection with the dispositions.
81
10. Fair Value Measurements
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 current and long-term 2021 WTI Contingency
Payout and 2022 WTI Contingency Payout, included within “Accounts payable and accrued liabilities” and “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 (collectively “Debt Facilities”) 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
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.
2022 and 2021 Acquisitions. The Company recognized the assets acquired in our 2022 and 2021 acquisitions at cost on 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 and income taxes 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:
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 are periodically verified against quotes from brokers and 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.
82
The following table presents our assets and liabilities that are measured on a recurring basis as of December 31, 2022 and
2021, 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.
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
(in thousands)
December 31, 2022
Assets
Natural Gas Derivatives
$
25,960 $
— $
25,960 $
Natural Gas Basis Derivatives
Oil Derivatives
NGL Derivatives
Liabilities
Natural Gas Derivatives
Natural Gas Basis Derivatives
Oil Derivatives
NGL Derivatives
2022 WTI Contingency Payout
2021 WTI Contingency Payout
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
2021 WTI Contingency Payout
26,023
14,604
10,134
28,579
409
19,442
104
2,135
1,453
1,159 $
1,025
371
3
449
31,801
452
21,330
514
1,941
1,841
—
—
—
—
—
—
—
—
—
— $
—
—
—
—
—
—
—
—
—
—
26,023
14,604
10,134
28,579
409
19,442
104
2,135
1,453
1,159 $
1,025
371
3
449
31,801
452
21,330
514
1,941
1,841
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
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. Estimates for the initial recognition of asset retirement obligations are
derived from historical costs as well as management's expectation of future cost environments and other unobservable inputs.
As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as
Level 3 fair value measurements. 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
83
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.
The following provides a roll-forward of our asset retirement obligations (in thousands):
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
Accretion expense
Liabilities incurred for new wells, acquired wells and facilities construction
Reductions due to sold wells and facilities
Reductions due to plugged wells and facilities
Revisions in estimates
Asset Retirement Obligations as of December 31, 2022
$
$
$
4,974
306
1,120
(192)
(158)
6,050
534
3,032
(57)
(22)
919
10,456
At December 31, 2022 and 2021, approximately $1.3 million and $0.5 million, respectively, of our asset retirement
obligations were classified as current liabilities in “Accounts payable and accrued liabilities” on the accompanying consolidated
balance sheets.
84
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, 2022
Proved oil and gas properties
Unproved oil and gas properties
Total
Accumulated depreciation, depletion, amortization and impairment
Net capitalized costs
December 31, 2021
Proved oil and gas properties
Unproved oil and gas properties
Total
Accumulated depreciation, depletion, amortization and impairment
Net capitalized costs
Total
2,506,853
16,272
2,523,125
(1,000,086)
1,523,039
1,588,978
17,090
1,606,068
(866,339)
739,729
$
$
$
$
There were $16.3 million and $17.1 million of unproved property costs at December 31, 2022 and 2021, 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, 2022
and 2021.
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
(1) (3)
Development
Acquisition of property(4)
Total acquisition, exploration, and development
(2)
Year Ended December
31, 2022
Year Ended December
31, 2021
$
$
20,276 $
—
308,240
592,945
921,461 $
7,241
—
122,712
138,016
267,969
(1) Facility construction costs and capital costs have been included in development costs, and totaled $23.8 million and $9.2 million for the years ended
December 31, 2022 and 2021, respectively.
(2) Includes capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately $4.3
million and $4.8 million for the years ended December 31, 2022 and 2021, respectively. There was no capitalized interest on unproved properties for the years
ended December 31, 2022 and 2021.
(3) Includes asset retirement obligations incurred, including revisions, of approximately $1.2 million and $0.1 million for the years ended December 31, 2022
and 2021, respectively. Does not include accrued payments associated with our Bay De Chene sale for the years ended December 31, 2022 and 2021.
(4) Includes $156.3 million and $83.5 million in equity consideration for acquisitions of property for the years ended December 31, 2022 and 2021. Also
includes $2.7 million and $0.7 million in asset retirement obligations assumed in connection with acquisitions of property for the years ended December 31,
2022 and 2021.
85
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 H.J. Gruy and Associates, Inc. (“Gruy”) as of December 31,
2022, 2021 and 2020. Proved reserves, as of December 31, 2022, 2021 and 2020, 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 2022 average adjusted prices after
differentials used in our calculations were $6.14 per Mcf of natural gas, $94.36 per barrel of oil, and $34.76 per barrel of NGL
compared to $3.75 per Mcf of natural gas, $63.98 per barrel of oil, and $25.29 per barrel of NGL for the 12-month average
2021 prices and $2.13 per Mcf of natural gas, $37.83 per barrel of oil, and $11.66 per barrel of NGL for 2020.
Total
Natural Gas
Oil
NGL
Estimates of Proved Reserves
Proved reserves as of December 31, 2020
Extensions, discoveries, and other additions (3)
Revisions of previous estimates
Purchases of minerals in place (4)
Production
(1)
Proved reserves as of December 31, 2021
Extensions, discoveries, and other additions (3)
Revisions of previous estimates
Purchases of minerals in place (4)
Sales of minerals in place
(1)
Production
(Mcf)
948,094,943
324,625,474
(Mcfe)
1,106,415,080
359,374,661
(198,471,444) (199,625,710)
226,564,990
(78,112,880)
142,794,045
(60,509,606)
(Bbls)
12,531,501
3,930,631
(1,644,367)
10,942,051
(1,461,657)
(Bbls)
13,855,188
1,860,900
1,836,746
3,019,773
(1,472,222)
1,415,770,407
567,235,133
1,155,379,146
514,492,260
24,298,159
5,423,639
19,100,385
3,366,839
(2,736,086)
561,425
(1,097,823)
548,238
355,470,688
126,849,989
26,393,737
11,709,713
(2,656,476)
(772,177)
(194,839)
(119,211)
(98,459,908)
(70,958,470)
(2,633,679)
(1,949,894)
Proved reserves as of December 31, 2022
2,234,623,758
1,725,552,173
52,189,194
32,656,070
Proved developed reserves (2)
December 31, 2020
December 31, 2021
December 31, 2022
Proved undeveloped reserves
December 31, 2020
December 31, 2021
December 31, 2022
506,149,407
658,230,618
952,778,882
415,390,459
525,736,580
695,481,580
6,962,826
9,692,076
23,360,025
8,163,666
12,390,263
19,522,859
600,265,673
757,539,789
1,281,844,876
532,704,484
629,642,566
1,030,070,593
5,568,676
14,606,082
28,829,169
5,691,522
6,710,122
13,133,211
(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 2022 include approximately 47.3 Bcfe due to performance revisions, 8.9 Bcfe due to
demonstrated changes in operating expenses and 2.8 Bcfe attributable to the reclassification of PUDs to unproved due to changes in the Company's five-year
development plan, partially offset by positive revision of 35.8 Bcfe due to incremental interest related to non-consent participation of a working interest partner
in our Webb County Gas operating area and a Company-wide positive commodity sales price revisions of 20.5 Bcfe. The downward revisions for 2021 include
approximately 170.6 Bcfe attributable to the reclassification of PUDs to unproved due to changes in the Company's five-year development plan, 62.9 Bcfe due
to performance revisions, and 6.6 due to demonstrated changes in operating expenses, partially offset by Company-wide positive commodity sales price
revisions of 41.7 Bcfe.
(2) At December 31, 2022 and 2021, 43% and 46% of our reserves were proved developed.
(3) The 2022 additions were due to discovery and extensions of 567.2 Bcfe attributable to drilling results of 159.5 Bcfe and leasing of adjacent acreage of 407.7
Bcfe. Similarly, the 2021 additions were due to discovery and extensions of 359.4 Bcfe attributable to drilling results of 331.5 Bcfe and leasing of adjacent
acreage of 27.8 Bcfe.
(4) Purchases of minerals in place for 2022 are 355.5 Bcfe and relate to our May 2022 Acquisition of 85.2 Bcfe, June 2022 Acquisition of 202.0 Bcfe, August
2022 Acquisition of 25.8 Bcfe and October 2022 Acquisition of 42.5 Bcfe. Purchases of minerals in place for 2021 are 226.6 Bcfe and relate to our August
2021 Acquisition of 113.6 Bcfe, October 2021 Acquisition of 44.8 Bcfe, November 2021 Acquisition of 54.8 Bcfe and several smaller acquisitions totaling
13.4 Bcfe.
86
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,
2022
2021
$
16,660,470 $
6,370,628
(4,039,248)
(1,853,856)
(2,063,508)
(753,046)
10,557,714
3,763,726
(1,953,345)
(584,613)
8,604,369
3,179,113
(4,564,123)
(1,620,651)
$
4,040,246 $
1,558,462
The Standardized Measure of discounted future net cash flows from production of proved reserves as of December 31,
2022 and 2021, 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.
87
The following are the principal sources of changes in the Standardized Measure of discounted future net cash flows (in
thousands) for the years ended December 31, 2022 and 2021:
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
Changing in timing and 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
2022
$ 1,558,462 $
2021
512,952
1,852,439
781,786
(208,188)
1,569
(4,218)
(43,379)
181,678
(176,112)
52,627
29,303
1,645,599
821,906
968,093
1,051,869
400,008
345,300
(5,209)
—
(621,686)
(336,028)
108,566
59,318
(665,448)
(244,994)
2,481,784
1,045,510
$ 4,040,246 $ 1,558,462
88
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
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 2022 that materially
affected, or are reasonably likely to materially affect, our internal control over financial reporting.
89
Item 9B. Other Information
None.
90
Item 9C. Disclosures Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
91
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 16, 2023 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 16, 2023 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 16, 2023 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 16, 2023 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 16, 2023 annual shareholders' meeting is incorporated herein
by reference.
92
Item 15. Exhibits and Financial Statement Schedules.
PART IV
1. The following consolidated financial statements of SilverBow together with the report thereon of BDO USA, LLP dated
March 2, 2023, 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
52
53
54
56
57
58
59
60
3.1
3.2
3.3
3.4
4.1
4.2
4.3
4.4
4.5
4.6
4.7
Certificate of Incorporation of Swift Energy Company, effective April 22, 2016 (filed as Exhibit 3.1 to Swift
Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
Certificate of Amendment to Certificate of Incorporation, effective May 5, 2017 (filed as Exhibit 3.1 to
SilverBow Resources, Inc.’s Current Report on Form 8-K filed May 5, 2017, File No. 001-08754).
Second Amended and Restated Bylaws of SilverBow Resources, Inc., effective October 31, 2022 (incorporated
by reference as Exhibit 3.2 to SilverBow Resources, Inc.’s Form 10-Q filed November 3, 2022, File No.
001-08754).
Certificate of Designation, Preferences, and Rights of Series B Junior Participating Preferred Stock of the
Company (incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K
filed September 20, 2022, File No. 001-08754).
Form of stock certificate for common stock, $0.01 par value per share (incorporated by reference as Exhibit 4.1
to SilverBow Resources, Inc.’s Form 10-K filed March 3, 2022, File No. 001-08754).
Rights Agreement dated as of September 20, 2022, by and between the Company and American Stock Transfer
& Trust Company, LLC, as rights agent, which includes as Exhibit B the Form of Rights Certificate
(incorporated by reference as Exhibit 4.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed
September 20, 2022, File No. 001-08754).
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)
93
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)
Registration Rights Agreement, dated May 10, 2022, between SilverBow Resources, Inc. and SandPoint
Operating, LLC (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form S-3 filed May
13, 2022, File No.333-264936).
Registration Rights Agreement, dated June 30, 2022, between SilverBow Resources, Inc. and Sundance Energy,
Inc. (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form S-3 filed July 6, 2022, File
No. 333-266032).
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).
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).
4.8
4.9
4.10
4.11
4.12*
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
Ninth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement dated as of April
12, 2022, 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 13, 2022, File No. 001-08754).
10.10
94
Tenth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement dated as of June
22, 2022, 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 June 24, 2022, 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).
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).
Third Amendment to the SilverBow Resources, Inc. 2016 Equity Incentive Plan, effective May 17, 2022
(incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed May 17, 2022, 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 – 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).
10.11
10.12
10.13
10.14
10.15
10.16+
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+
95
10.30+
10.31+
10.32+
10.33+
10.34+
10.35+
10.36+
10.37+
10.38+
10.39+
10.40+
10.41+
10.42+
10.43+
10.44+
10.45+
10.46+
10.47+
10.48
10.49
10.50
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).
Form of Restricted Stock Unit Agreement - Non-Employee Directors 2022 (incorporated by reference as Exhibit
10.1 to SilverBow Resources, Inc.’s Form 10-Q filed May 5, 2022, File No. 001-08754).
Form of Restricted Stock Unit Agreement – Officers 2022 (incorporated by reference as Exhibit 10.2 to
SilverBow Resources, Inc.’s Form 10-Q filed May 5, 2022, File No. 001-08754).
Form of Performance Share Unit Agreement – Officers 2022.(incorporated by reference as Exhibit 10.3 to
SilverBow Resources, Inc.’s Form 10-Q filed May 5, 2022, 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).
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 (incorporated by
reference as Exhibit 10.44 to SilverBow Resources, Inc.’s Form 10-K filed March 1, 2022, File No. 001-08754).
Purchase and Sale Agreement, dated April 13, 2022, between SilverBow Resources, Inc. and SilverBow
Resources Operating, LLC and Sundance Energy, Inc., Armadillo E&P, Inc. and SEA Eagle Ford, LLC
(incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed April 14, 2022, File
No. 001-08754).
Voting Agreement, dated April 13, 2022, between SilverBow Resources, Inc. and SVMF 71 LLC (incorporated
by reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form 8-K filed April 14, 2022, File No. 001-08754).
96
21 *
23.1*
23.2*
31.1*
31.2*
32#
99.1*
101*
104*
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 23, 2023.
The following materials from SilverBow Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended
December 31, 2022 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).
* Filed herewith.
# Furnished herewith.
+ Management contract or compensatory plan or arrangement.
97
Item 16. 10-K Summary.
None.
98
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 2, 2023.
SIGNATURES
SILVERBOW RESOURCES, INC.
By: /s/ Sean C. Woolverton
Sean C. Woolverton
Chief Executive Officer
99
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
/s/ Sean C. Woolverton
Sean C. Woolverton
/s/ Christopher M. Abundis
Christopher M. Abundis
/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/ Jennifer M. Grigsby
Jennifer M. Grigsby
/s/ Christoph O. Majeske
Christoph O. Majeske
/s/ Kathleen McAllister
Kathleen McAllister
/s/ Charles W. Wampler
Charles W. Wampler
Chief Executive Officer and Director
March 2, 2023
Executive Vice President,
Chief Financial Officer and
General Counsel
March 2, 2023
Vice President of Accounting and
March 2, 2023
Controller
Chairman of the Board
Director
March 2, 2023
Director
March 2, 2023
Director
March 2, 2023
Director
March 2, 2023
Director
March 2, 2023
Director
March 2, 2023
Director
March 2, 2023
Director
March 2, 2023
100
INVESTOR
INFORMATION
BOARD OF DIRECTORS
MARCUS C. ROWLAND,
CHAIRMAN OF THE BOARD
Founder and Director
IOG Capital
MICHAEL DUGINSKI
President and Chief Executive Officer
Sentinel Peak Resources
GABRIEL L. ELLISOR
Managing Partner
3BAR Industries LLC
CHRISTOPH O. MAJESKE
Advisor
Strategic Value Partners
KATHLEEN MCALLISTER
Former Chief Executive Officer
and Chief Financial Officer
Transocean Partners LLC
CHARLES W. WAMPLER
Chief Executive Officer & President
Resource Rock Exploration II, LLC
DAVID GEENBERG
Head of North American Investment Team
Strategic Value Partners
SEAN C. WOOLVERTON
Chief Executive Officer
SilverBow Resources, Inc.
JENNIFER M. GRIGSBY
Former Executive Vice President
and Chief Financial Officer
Ascent Resources LLC
MANAGEMENT TEAM
SEAN C. WOOLVERTON
Chief Executive Officer
CHRISTOPHER M. ABUNDIS
Executive Vice President,
Chief Financial Officer
and General Counsel
STEVEN W. ADAM
Executive Vice President
and Chief Operating Officer
JENNIFER CADENA
Vice President of Land, ESG
and Assistant General Counsel
ANNIE FOLEY
Vice President of Administration,
Assistant General Counsel and Secretary
LAURA GU
Vice President of Corporate
and Asset Development
JEFF MAGIDS
Vice President of Finance
and Investor Relations
STEPHEN P. SCHMITT
Vice President of Energy Marketing
W. ERIC SCHULTZ
Vice President of Accounting
and Controller
CORPORATE
HEADQUARTERS
SILVERBOW
RESOURCES, INC.
920 Memorial City Way, Ste. 850
Houston, Texas 77024
PHONE 281-874-2700
888-991-SBOW
EMAIL info@sbow.com
TRANSFER AGENT
AND REGISTRAR
AMERICAN STOCK TRANSFER
& TRUST COMPANY
6201 15th Avenue
Brooklyn, New York 11219
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 16, 2023
WEBSITE
SBOW.com