CIVITAS RESOURCES, INC. The following discussion and analysis contains forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions, and resources. Such forward-looking statements should be read in conjunction with our disclosures under "Item 1A. Risk Factors" of this Form 10-K. This section of this Form 10-K generally discusses 2020 and 2019 results and year-to-year comparisons between 2020 and 2019. Discussions of 2018 items and year-to-year comparisons between 2019 and 2018 that are not included in this Form 10-K can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 ofBonanza Creek's Annual Report on Form 10-K for the fiscal year endedDecember 31, 2019 . Executive Summary We are an independentDenver -based exploration and production company focused on the acquisition, development, and extraction of oil and associated liquids-rich natural gas inthe United States . Our oil and liquids-weighted assets and operations are concentrated in the rural portions of the Wattenberg Field inColorado . Our development and extraction activities are primarily directed at the horizontal development of the Niobrara and Codell formations in theDJ Basin . The majority of our revenues are generated through the sale of oil, natural gas, and natural gas liquids production. The Company's primary objective is to maximize shareholder returns by responsibly developing our oil and gas resources. We seek to balance production growth with maintaining a conservative balance sheet. Key aspects of our strategy include multi-well pad development across our leasehold, enhanced completions through continuous design evaluation, utilization of scaled infrastructure, continuous safety improvement, strict adherence to health and safety regulations, and environmental stewardship. Financial and Operating Results Our 2020 financial and operational results include: •General and administrative expense per Boe decreased by 18% for the year endedDecember 31, 2020 when compared to the same period during 2019; •Lease operating expense decreased by$3.3 million or$0.57 per Boe for the year endedDecember 31, 2020 when compared to the same period during 2019; •Crude oil equivalent sales volumes increased 8% for the year endedDecember 31, 2020 when compared to the same period during 2019, despite the significant curtailment of our drilling and completion program in response to the drop in commodity prices; •Borrowings under our Credit Facility were reduced by$80.0 million to zero during the year endedDecember 31, 2020 ; •Total liquidity was$284.7 million atDecember 31, 2020 , consisting of cash on hand plus funds available under our Credit Facility. Please refer to Liquidity and Capital Resources below for additional discussion; •Cash flows provided by operating activities for the year endedDecember 31, 2020 was$158.8 million , as compared to cash flows provided by operating activities of$224.6 million during the year endedDecember 31, 2019 . Please refer to Liquidity and Capital Resources below for additional discussion; •Proved reserves of 118.2 MMBoe as ofDecember 31, 2020 decreased by 3% when compared to proved reserves as ofDecember 31, 2019 ; and •Capital expenditures, inclusive of accruals, were$67.7 million during the year endedDecember 31, 2020 , which was within guidance. 62 -------------------------------------------------------------------------------- Table of Contents Rocky Mountain Infrastructure The Company's gathering, treating, and production facilities, maintained under itsRocky Mountain Infrastructure, LLC ("RMI") subsidiary, provide many operational benefits to the Company and provide cost economies of a centralized system. The RMI facilities reduce gathering system pressures at the wellhead, thereby improving hydrocarbon recovery. Additionally, with eleven interconnects to four different natural gas processors, RMI helps ensure that the Company's production is not constrained by any single midstream service provider. Furthermore, in 2019, the Company installed a new oil gathering line toRiverside Terminal (on theGrand Mesa Pipeline ), which resulted in a corresponding$1.25 to$1.50 per barrel reduction to our oil differentials for barrels transported on such gathering line. The total value of reduced oil differentials during the year endedDecember 31, 2020 was approximately$6.2 million . Finally, the RMI system reduces facility site footprints, leading to more cost-efficient operations, reduced emissions, and reduced surface disturbance. The net book value of the Company's RMI assets was$153.0 million as ofDecember 31, 2020 . Current Events and Outlook The worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19, and various governmental actions taken to mitigate the impact of COVID-19, have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision bySaudi Arabia inMarch 2020 to drastically reduce export prices and increase oil production further increased the excess supply of oil and natural gas. Due to the decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment as a result of these events, we have suspended all drilling and significantly reduced completion and infrastructure activities. The COVID-19 outbreak and its development into a pandemic inMarch 2020 have also required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, suppliers, and the communities in which we operate. Our operational employees are currently still able to work on site. However, we have taken various precautionary measures with respect to our operational employees such as requiring them to verify they have not experienced any symptoms consistent with COVID-19, or been in close contact with someone showing such symptoms, before reporting to the work site, quarantining any operational employees who have shown signs of COVID-19 (regardless of whether such employee has been confirmed to be infected), and imposing social distancing requirements on work sites, all in accordance with the guidelines released by theCenters for Disease Control and Prevention . We have not yet experienced any material operational disruptions (including disruptions from our suppliers and service providers) as a result of a COVID-19 outbreak. Due to the unprecedented drop in commodity prices that commenced in earlyMarch 2020 , the Company updated its 2020 operating plan and reduced planned development activity including limited drilling and completion activity that concluded inMarch 2020 , with a small amount of additional completion work done inJuly 2020 . In further response to the drop in commodity prices, our named executive officers and independent directors voluntarily reduced their compensation. Effective in earlyApril 2020 , our Chief Executive Officer's salary was reduced by 12.5%, the other named executive officers' salaries were each reduced by 10%, and our independent directors' base annual cash retainers were reduced by 15%. In addition, the Company completed a 12% reduction in its workforce during the second quarter. Finally, the Company implemented approximately$8 million in LOE and RMI operating expense savings compared to the Company's original 2020 plan. The Company's first quarter 2021 capital budget of$35 million to$40 million assumes the beginning of completion activities on 30 gross (25.8 net) drilled, uncompleted wells. The Company is providing guidance for the first quarter of 2021 forBonanza Creek as a stand-alone company. Additional guidance for 2021 on a combined basis will be provided after the closing of the HighPoint Acquisition. Actual capital expenditures could vary significantly based on, among other things, market conditions, commodity prices, drilling and completion costs, and well results. 63 -------------------------------------------------------------------------------- Table of Contents Results of Operations The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto contained in Part II, Item 8 of this Annual Report on Form 10-K. Comparative results of operations for the period indicated are discussed below. The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated: Year Ended
2020 2019 Change Percent Change
Revenues (in thousands):
Crude oil sales(1) $ 172,787 $ 266,480 $ (93,693) (35) %
Natural gas sales(2) 20,562 24,624 (4,062) (16) %
Natural gas liquids sales 19,311 16,060 3,251 20 %
Product revenue $ 212,660 $ 307,164 $ (94,504) (31) %
Sales Volumes:
Crude oil (MBbls) 5,019.4 5,135.9 (116.5) (2) %
Natural gas (MMcf) 14,165.7 11,966.8 2,198.9 18 %
Natural gas liquids (MBbls) 1,858.2 1,431.1 427.1 30 %
Crude oil equivalent (MBoe)(3) 9,238.6 8,561.5 677.1 8 %
Average Sales Prices (before derivatives)(4):
Crude oil (per Bbl) $ 34.42 $ 51.89 $ (17.47) (34) %
Natural gas (per Mcf) $ 1.45 $ 2.06 $ (0.61) (30) %
Natural gas liquids (per Bbl) $ 10.39 $ 11.22 $ (0.83) (7) %
Crude oil equivalent (per Boe)(3) $ 23.02 $ 35.88 $ (12.86) (36) %
Average Sales Prices (after derivatives)(4):
Crude oil (per Bbl) $ 44.41 $ 52.12 $ (7.71) (15) %
Natural gas (per Mcf) $ 1.40 $ 2.10 $ (0.70) (33) %
Natural gas liquids (per Bbl) $ 10.39 $ 11.22 $ (0.83) (7) %
Crude oil equivalent (per Boe)(3) $ 28.37 $ 36.07 $ (7.70) (21) %
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(1)Crude oil sales excludes$1.7 million and$2.4 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the years endedDecember 31, 2020 and 2019, respectively. (2)Natural gas sales excludes$3.7 million and$3.7 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the years endedDecember 31, 2020 and 2019, respectively. (3)Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil. (4)Derivatives economically hedge the price we receive for crude oil and natural gas. For the year endedDecember 31, 2020 , the derivative cash settlement gain for oil was$50.1 million , and the derivative cash settlement loss for natural gas contracts was$0.7 million . For the year endedDecember 31, 2019 , the derivative cash settlement gain for oil and natural gas was$1.2 million and$0.5 million , respectively. Please refer to Part II, Item 8, Note 12 - Derivatives for additional disclosures. Product revenues decreased by 31% to$212.7 million for the year endedDecember 31, 2020 compared to$307.2 million for the year endedDecember 31, 2019 . The decrease was largely due to a$12.86 or 36% decrease in oil equivalent pricing excluding the impact of derivatives, partially offset by an 8% increase in sales volumes. The increase in sales volumes is due to turning 26 gross wells to sales during the year endingDecember 31, 2020 . 64 -------------------------------------------------------------------------------- Table of Contents The following table summarizes our operating expenses for the periods indicated (in thousands, except per Boe amounts): Year Ended December 31, 2020 2019 Change Percent Change Operating Expenses: Lease operating expense$ 21,957 $ 25,249 $ (3,292) (13) % Midstream operating expense 14,948 12,014 2,934 24 % Gathering, transportation, and processing 16,932 16,682 250 1 % Severance and ad valorem taxes 3,787 25,598 (21,811) (85) % Exploration 596 797 (201) (25) % Depreciation, depletion, and amortization 91,242 76,453 14,789 19 % Abandonment and impairment of unproved properties 37,343 11,201 26,142 233 % Bad debt expense 818 - 818 100 % Merger transaction costs 6,676 - 6,676 100 % General and administrative expense 34,936 39,668 (4,732) (12) % Operating expenses$ 229,235 $ 207,662 $ 21,573 10 % Selected Costs ($ per Boe): Lease operating expense$ 2.38 $ 2.95 $ (0.57) (19) % Midstream operating expense 1.62 1.40 0.22 16 % Gathering, transportation, and processing 1.83 1.95 (0.12) (6) % Severance and ad valorem taxes 0.41 2.99 (2.58) (86) % Exploration 0.06 0.09 (0.03) (33) % Depreciation, depletion, and amortization 9.88 8.93 0.95 11 % Abandonment and impairment of unproved properties 4.04 1.31 2.73 208 % Bad debt expense 0.09 - 0.09 100 % Merger transaction costs 0.72 - 0.72 100 % General and administrative expense 3.78 4.63 (0.85) (18) % Operating expenses$ 24.81 $ 24.25 $ 0.56 2 % Operating expenses, excluding impairments and abandonments and unused commitments$ 20.77 $ 22.94 $ (2.17) (9) % Lease operating expense. Our lease operating expense decreased$3.3 million , or 13%, to$22.0 million for the year endedDecember 31, 2020 from the year endedDecember 31, 2019 , and decreased on an equivalent basis per Boe by 19%. The overall decrease was primarily due to reductions in pumping and gauging costs, compression costs, and several other areas implemented by the Company in a concerted effort to reduce costs in response to the decline in commodity pricing. Lease operating expense per unit decreased on a higher percentage basis due to oil equivalent sales volumes being 8% higher during the year endedDecember 31, 2020 as compared to the same period in 2019. Midstream operating expense. Our midstream operating expense increased$2.9 million to$14.9 million for the year endedDecember 31, 2020 from$12.0 million for the year endedDecember 31, 2019 , and increased on an equivalent basis per Boe by 16%. The increase was primarily due to a full year of costs associated with the Company's new and expanded oil gathering line connected to theRiverside Terminal that came online inJuly 2019 . Gathering, transportation, and processing. Gathering, transportation, and processing expense increased by$0.2 million to$16.9 million for the year endedDecember 31, 2020 from$16.7 million for the year endedDecember 31, 2019 . Natural gas and NGLs sales volumes have a direct correlation to gathering, transportation, and processing expense. Although natural gas and NGLs sales volumes increased 23% between the comparable periods, a decline in fees on sales contracts partially offset the increase in gathering, transportation, and processing expense. 65 -------------------------------------------------------------------------------- Table of Contents Severance and ad valorem taxes. Our severance and ad valorem taxes decreased by 85% to$3.8 million for the year endedDecember 31, 2020 from$25.6 million for the year endedDecember 31, 2019 . Severance and ad valorem taxes primarily correlate to revenue. Revenues decreased by 31% for the year endedDecember 31, 2020 when compared to the same period in 2019. Additionally, during 2020, we refined our tax estimate based on current mill levies, taxing districts, and company results based on commodity prices, which resulted in a total non-recurring adjustment of$16.3 million . Excluding this adjustment, our severance and ad valorem taxes were$20.1 million for the year endedDecember 31, 2020 , which is aligned with the reduction in revenues. Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense increased 19% to$91.2 million for the year endedDecember 31, 2020 from$76.5 million for the year endedDecember 31, 2019 , and increased 11% on a per Boe basis during the comparable period. The increase in depreciation, depletion, and amortization expense is the result of (i) a$121.7 million increase in the depletable property base and (ii) an increase in the depletion rate driven by an 8% increase in production between the comparable periods. Abandonment and impairment of unproved properties. During the years endedDecember 31, 2020 and 2019, we incurred$37.3 million and$11.2 million in abandonment and impairment of unproved properties primarily due to the reassessment of estimated probable and possible reserve locations based primarily upon economic viability and the expiration of non-core leases. Please refer to Part II, Item 8, Note 1 - Summary of Significant Accounting Policies for additional discussion on our impairment policy and practices. Merger transaction costs. During the year endedDecember 31, 2020 , we incurred$6.7 million in legal, advisor, and other costs associated with the anticipated HighPoint Acquisition compared to no such costs during the comparable 2019 period. General and administrative expense. Our general and administrative expense decreased by$4.8 million to$34.9 million for the year endedDecember 31, 2020 , compared to$39.7 million for the year endedDecember 31, 2019 , and decreased by 18% on a per Boe basis between the comparable periods. The decrease in general and administrative expense between the comparable periods is primarily due to a decrease in salaries, benefits, and stock compensation expense due to our reduced workforce, partially offset by an increase in severance costs. General and administrative expense per Boe decreased on a higher percentage basis due to oil equivalent sales volumes being 8% higher during the year endedDecember 31, 2020 as compared to the same period in 2019. Derivative gain (loss). Our derivative gain for the year endedDecember 31, 2020 was$53.5 million as compared to a loss of$37.1 million for year endedDecember 31, 2019 . Our derivative gain is due to settlements and fair market value adjustments caused by market prices being lower than our contracted hedge prices. Please refer to Part II, Item 8, Note 12 - Derivatives for additional discussion. Interest expense. Our interest expense for the years endedDecember 31, 2020 and 2019 was$2.0 million and$2.7 million , respectively. Average debt outstanding for the years endedDecember 31, 2020 and 2019 was$53.2 million and$77.2 million , respectively. The components of interest expense for the periods presented are as follows (in thousands): Year Ended December 31, 2020 2019 Credit Facility $ 1,760
$ 3,450 Commitment fees on available borrowing base under the Credit Facility
1,181 1,112
Amortization of deferred financing costs 864 494
Capitalized interest (1,760) (2,406)
Total interest expense, net $ 2,045 $ 2,650
66-------------------------------------------------------------------------------- Table of Contents Liquidity and Capital Resources The Company's anticipated sources of liquidity include cash from operating activities, borrowings under the Credit Facility, proceeds from sales of assets, and potential proceeds from equity and/or debt capital markets. Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity, regulatory constraints, and other supply chain dynamics, among other factors. To mitigate some of the pricing risk, we have hedged approximately 6,200 Bbls per day in 2021, representing approximately 50% of our oil sales volume during the three months endedDecember 31, 2020 . As ofDecember 31, 2020 , our liquidity was$284.7 million , consisting of cash on hand of$24.7 million and$260.0 million of available borrowing capacity on our Credit Facility. Please refer to Part II, Item 8, Note 6 - Long-term Debt for additional discussion. We anticipate investing approximately$35 million to$40 million , which will support the beginning of completion activities on 30 gross (25.8 net) wells in the first quarter of 2021 as a stand-alone company. Additional guidance for 2021 on a combined basis will be provided after the closing of the HighPoint Acquisition. The following table summarizes our cash flows and other financial measures for the periods indicated (in thousands):
Year Ended
2020 2019
Net cash provided by operating activities $ 158,796 $ 224,647
Net cash used in investing activities (63,799) (255,158)
Net cash provided by (used in) financing activities (81,247) 28,604
Cash, cash equivalents, and restricted cash 24,845 11,095
Acquisition of oil and gas properties (3,210) (14,087)
Exploration and development of oil and gas properties (60,149) (242,487)
Cash flows provided by operating activities
For the years ended December 31, 2020 and 2019, the cash receipts and
disbursements were attributable to our normal operating cycle. See Results of
Operations above for more information on the factors driving these changes.
Cash flows used in investing activities
Expenditures for development of oil and natural gas properties are the primary
use of our capital resources. The Company spent $60.1 million and $242.5 million
on the exploration and development of oil and gas properties during the years
ended December 31, 2020 and 2019, respectively. The decrease in capital
expenditures between the periods is primarily due to reduced drilling and
completion activity in response to the unprecedented drop in commodity prices
between the comparable periods. The Company also spent $10.9 million less on
acquisitions of oil and gas properties during the year ended December 31, 2020
when compared to the same period in 2019.
Cash flows provided by financing activities
Net cash used in financing activities for the year ended December 31, 2020 was
$81.2 million , compared to cash provided by financing activities for the year
ended December 31, 2019 of $28.6 million . The change was primarily due to a
$110.0 million increase in net payments on our Credit Facility between the
comparable periods.
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Material Commitments
We had the following material commitments as of December 31, 2020 (in
thousands):
Less than 1 More than 5
Total Year 1-3 Years 3-5 Years Years
Delivery commitments(1) $ 49,701 $ 22,403 $ 27,298 $ - $ -
Operating leases(2) 31,542 12,836 16,159 2,547 -
Asset retirement
obligations(3) 28,699 - 14,774 396 13,529
Total $ 109,942 $ 35,239 $ 58,231 $ 2,943 $ 13,529
(1)The calculation on the delivery commitments is based on the minimum gross
volume commitment schedule (as defined in the NGL Crude agreement) and
applicable differential fees. Please refer to Note 7 - Commitments and
Contingencies for additional discussion on this agreement.
(2)The Company has included the minimum future commitments for its long-term
operating leases. Such leases are reflected at undiscounted values. Please refer
to Part II, Item 8, Note 2 - Leases, for additional discussion.
(3)Amounts represent our estimated future retirement obligations on a discounted
basis. The discounted obligations are recorded as liabilities on our
accompanying balance sheets as of December 31, 2020 and 2019. Because these
costs typically extend many years into the future, management prepares estimates
and makes judgments that are subject to future revisions based upon numerous
factors. Please refer to Part II, Item 8, Note 10 - Asset Retirement Obligation,
for additional discussion.
Credit Facility
In December 2018 , the Company entered into a reserve-based revolving facility,
as the borrower, with JPMorgan Chase Bank, N.A ., as the administrative agent,
and a syndicate of financial institutions, as lenders. The $750.0 million Credit
Facility has a maturity date of December 7, 2023 and was governed by an initial
borrowing base of $350.0 million . The Credit Facility borrowing base is
redetermined on a semi-annual basis. In June 2020 , the borrowing base and
aggregate elected commitments were reduced to $260.0 million . The most recent
redetermination was concluded on December 18, 2020 , resulting in a reaffirmation
of the borrowing base at $260.0 million . The next scheduled redetermination is
set to occur in May 2021 .
The Credit Facility is guaranteed by all wholly-owned subsidiaries of the
Company (each, a "Guarantor" and, together with the Company, the "Credit
Parties"), and is secured by first priority security interests on substantially
all assets of each Credit Party , subject to customary exceptions.
Under the original terms of the Credit Facility, borrowings bore interest at a
per annum rate equal to, at the option of the Company, either (i) a London
InterBank Offered Rate ("LIBOR"), subject to a 0% LIBOR floor plus a margin of
1.75% to 2.75%, based on the utilization of the Credit Facility (the "Eurodollar
Rate") or (ii) a fluctuating interest rate per annum equal to the greatest of
(a) the rate of interest publicly announced by JPMorgan Chase Bank, N.A . as its
prime rate, (b) the rate of interest published by the Federal Reserve Bank of
New York as the federal funds effective rate, (c) the rate of interest published
by the Federal Reserve Bank of New York as the overnight bank funding rate, or
(d) a LIBOR offered rate for a one month interest period, subject to a 0% LIBOR
floor plus a margin of 0.75% to 1.75%, based on the utilization of the Credit
Facility (the "Reference Rate"). Interest on borrowings that bear interest at
the Eurodollar Rate shall be payable on the last day of the applicable interest
period selected by the Company, which shall be one, two, three, or six months,
and interest on borrowings that bear interest at the Reference Rate shall be
payable quarterly in arrears.
The Credit Facility contains customary representations and affirmative
covenants. The Credit Facility also contains customary negative covenants,
which, among other things, and subject to certain exceptions, include
restrictions on (i) liens, (ii) indebtedness, guarantees and other obligations,
(iii) restrictions in agreements on liens and distributions, (iv) mergers or
consolidations, (v) asset sales, (vi) restricted payments, (vii) investments,
(viii) affiliate transactions, (ix) change of business, (x) foreign operations
or subsidiaries, (xi) name changes, (xii) use of proceeds, letters of credit,
(xiii) gas imbalances, (xiv) hedging transactions, (xv) additional subsidiaries,
(xvi) changes in fiscal year or fiscal quarter, (xvii) operating leases,
(xviii) prepayments of certain debt and other obligations, (xix) sales or
discounts of receivables, and (xx) dividend payments. The Credit Parties are
subject to certain financial covenants under the Credit Facility, as tested on
the last day of each fiscal quarter, including, without limitation, (i) a
maximum ratio of the Company's consolidated indebtedness (subject to certain
exclusions) to earnings before interest, income taxes, depreciation, depletion,
and amortization, exploration expense, and other non-cash charges ("EBITDAX")
and (ii) a current ratio, as defined in the agreement, inclusive of the unused
Commitments then available to be borrowed, to not be less than 1.00 to 1.00.
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On June 18, 2020 , in conjunction with the borrowing base redetermination, the
Company, together with certain of its subsidiaries, entered into the First
Amendment (the "First Amendment") to the Credit Facility (as amended, restated,
supplemented or otherwise modified) to, among other things: (i) implement
certain anti-cash hoarding provisions, including a weekly mandatory prepayment
requirement with respect to the excess of the Company's consolidated cash
balance over $35.0 million ; (ii) require that, in order to borrow or issue a
letter of credit under the Credit Agreement, the consolidated cash balance not
exceed the greater of $35.0 million (both before and after giving effect to such
borrowing or letter of credit issuance), or expenditures in respect of oil and
gas properties in the ordinary course of business (as agreed to by the
administrative agent); (iii) decrease the maximum permitted net leverage ratio
from 4.00 to 3.50 and the maximum permitted leverage ratio for purposes of
making a restricted payment, restricted investment or optional or voluntary
redemption from 3.25 to 2.75; (iv) increase the Eurodollar Rate margin to 2.00%
to 3.00%; (v) increase the Reference Rate margin to 1.00% to 2.00%; and (vi)
amend certain other covenants and provisions.
The Company was in compliance with all covenants as of December 31, 2020 and
through the filing date of this report.
Our weighted-average interest rates on borrowings from the Credit Facility were
3.1% and 4.4% for the years ended December 31, 2020 and 2019, respectively. As
of December 31, 2020 and as of the date of filing, we had a zero balance on our
Credit Facility.
Non-GAAP Financial Measures
Adjusted EBITDAX represents earnings before interest, income taxes,
depreciation, depletion, and amortization, exploration expense, and other
non-cash and non-recurring charges. Adjusted EBITDAX excludes certain items that
we believe affect the comparability of operating results and can exclude items
that are generally non-recurring in nature or whose timing and/or amount cannot
be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we present
because we believe it provides useful additional information to investors and
analysts, as a performance measure, for analysis of our ability to internally
generate funds for exploration, development, acquisitions, and to service debt.
We are also subject to financial covenants under our Credit Facility based on
adjusted EBITDAX ratios as further described above in Liquidity and Capital
Resources. In addition, adjusted EBITDAX is widely used by professional research
analysts and others in the valuation, comparison, and investment recommendations
of companies in the oil and gas exploration and production industry. Adjusted
EBITDAX should not be considered in isolation or as a substitute for net income,
net cash provided by operating activities, or other profitability or liquidity
measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not
all items that affect net income and may vary among companies, the adjusted
EBITDAX amounts presented may not be comparable to similar metrics of other
companies.
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The following table presents a reconciliation of the GAAP financial measure of
net income to the non-GAAP financial measure of Adjusted EBITDAX (in thousands):
Year Ended December 31,
2020 2019
Net income $ 103,528 $ 67,067
Exploration 596 797
Depreciation, depletion, and amortization 91,242 76,453
Amortization of deferred financing costs - 248
Abandonment and impairment of unproved properties 37,343 11,201
Stock-based Compensation(1) 6,156 6,886
Severance costs(1) 1,337 751
Merger transaction costs 6,676 -
(Gain) loss on property transactions, net 1,398 (1,177)
Interest expense, net 2,045 2,650
Severance and ad valorem taxes adjustment(2) (16,291) -
Derivative (gain) loss (53,462) 37,145
Derivative cash settlements 49,406 1,691
Income tax benefit (60,547) -
Adjusted EBITDAX $ 169,427 $ 203,712 _______________________________
(1) Included as a portion of general and administrative expense in the accompanying consolidated statements of operations and comprehensive income ("statements of operations"). (2) Included as a portion of severance and ad valorem taxes in the accompanying statements of operations.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted inthe United States . The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates, and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. Please refer to Part II, Item 8, Note 1 - Summary of Significant Accounting Policies to our audited consolidated financial statements for a discussion of additional accounting policies and estimates made by management. Method of accounting for oil and natural gas properties Oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized at cost when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. All capitalized well costs and other associated costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and proved reserves, respectively. Costs of retired, sold, or abandoned properties that constitute a part of an amortization base (partial field) are charged or credited, net of proceeds, to accumulated depreciation, depletion, and amortization unless doing so significantly affects the 70 -------------------------------------------------------------------------------- Table of Contents unit-of-production amortization rate for an entire field, in which case a gain or loss is recognized. Gains or losses from the disposal of properties are recognized currently. Expenditures for maintenance, repairs, and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements, and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. Unproved properties are supported by probable and possible well locations and cost incurred to acquire unproved leases. Unproved lease costs are capitalized until the leases expire or when probable and possible well locations are reassessed and entire areas are no longer represented, at which time we expense the associated unproved lease costs. The expensing or expiration of unproved lease costs are recorded as abandonment or impairment of unproved properties in the statements of operations and comprehensive income (loss) in our consolidated financial statements. Lease costs are reclassified to proved properties and depleted on a unit-of-production basis once proved reserves have been assigned. For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property. Oil and natural gas reserve quantities and Standardized Measure Our third-party petroleum consultant prepared our estimates of oil and natural gas reserves and associated future net revenues. While theSEC has adopted rules which allow us to disclose proved, probable, and possible reserves, we have elected to disclose only proved reserves in this Annual Report on Form 10-K. TheSEC's revised rules define proved reserves as the 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 - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Our third party petroleum engineering consultant must make a number of subjective assumptions based on their professional judgment in developing reserve estimates. Reserve estimates are updated annually and consider recent production levels and other technical information about each field. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material. Revenue Recognition Sales of oil, natural gas, and NGLs are recognized when performance obligations are satisfied at the point control of the product is transferred to the customer. The Company's contracts' pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies. Please refer to Part II, Item 8, Note 1 - Summary of Significant Accounting Policies for more information. We record revenue in the month production is delivered to the purchaser. Payment is generally received within 30 to 60 days after the date of production. However, settlement statements for certain natural gas and NGLs sales may not be received for 30 to 60 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month in which payment is received from the purchaser. For the period fromJanuary 1, 2020 throughDecember 31, 2020 , revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Company has interests with other producers in certain properties, in which case the Company uses the entitlement method to account for gas imbalances. The Company had no material gas imbalances as ofDecember 31, 2020 and 2019. 71 -------------------------------------------------------------------------------- Table of Contents Impairment of proved properties We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred and at least annually. We estimate the expected undiscounted future cash flows of our oil and natural gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs, using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded. Impairment of unproved properties The unproved property balance at emergence from bankruptcy represents probable and possible well locations that are reassessed at least annually. The assessment of probable and possible locations incorporates key factors such as economic viability, surface constraints, wells per section, limitations on operatorship due to working interest changes, and any relevant components at such time. Changes in probable and possible locations that result in entire areas no longer being represented in the reserve run are impaired. Leases acquired post-emergence are assessed for impairment applying the following factors: •the remaining amount of unexpired term under our leases;
•our ability to actively manage and prioritize our capital expenditures to drill leases and to make payments to extend leases that may be closer to expiration;
•our ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;
•our ability to convey partial mineral ownership to other companies in exchange for their drilling of leases;
•our evaluation of the continuing successful results from the application of completion technology in the Wattenberg Field by us or by other operators in areas adjacent to or near our unproved properties; and
•strategic shifts in development areas.
The assessment of unproved properties to determine any possible impairment
requires significant judgment.
Asset retirement obligations
We record the fair value of a liability for a legal obligation to retire an
asset in the period in which the liability is incurred with the corresponding
cost capitalized by increasing the carrying amount of the related long-lived
asset. For oil and gas properties, this is the period in which the well is
drilled or acquired. The asset retirement obligation ("ARO") for oil and gas
properties represents the estimated amount we will incur to plug, abandon, and
remediate the properties at the end of their productive lives, in accordance
with applicable state laws. The liability is accreted to its present value each
period, and the capitalized cost is depreciated on the unit-of-production
method. The accretion expense is recorded as a component of depreciation,
depletion, and amortization in our accompanying statements of operations.
We determine the ARO by calculating the present value of estimated cash flows
related to the liability. Estimating the future ARO requires management to make
estimates and judgments regarding timing, existence of a liability, as well as
what constitutes adequate restoration. 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. To the extent
future revisions to these assumptions impact the fair value of the existing ARO
liability, a corresponding adjustment is made to the related asset.
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Derivatives
We record all derivative instruments on the balance sheet as either assets or
liabilities measured at their estimated fair value. We have not designated any
derivative instruments as hedges for accounting purposes, and we do not enter
into such instruments for speculative trading purposes. Derivative instruments
are adjusted to fair value every accounting period. Derivative cash settlements
and gains and losses from valuation changes in the remaining unsettled commodity
derivative instruments are reported under derivative gain (loss) in our
accompanying statements of operations.
Stock-based compensation
Restricted Stock Units. We recognize compensation expense for all restricted
stock units granted to employees and directors. Stock-based compensation expense
is measured at the grant date based on the fair value of the award and is
recognized as an expense on a straight-line basis over the requisite service
period, which is generally the vesting period. The fair value of restricted
stock grants is based on the value of our common stock on the date of grant.
Stock-based compensation expense recorded for restricted stock units is included
in general and administrative expenses on our accompanying statements of
operations.
Performance Stock Units. We recognize compensation expense for all performance
stock unit awards granted to employees. The number of shares of the Company's
common stock that may be issued to settle PSUs ranges from zero to two times the
number of PSUs awarded. The PSUs vest in their entirety at the end of the
three-year performance period. The total number of PSUs granted is split between
two performance criteria. The first criterion is based on a comparison of the
Company's absolute and relative total shareholder return ("TSR") for the
performance period compared with the TSRs of a group of peer companies for the
same performance period. The TSR for the Company and each of the peer companies
is determined by dividing (A) (i) the volume-weighted average share price for
the last 30 trading days of the performance period minus (ii) the
volume-weighted average share price for the 30 trading days preceding the
beginning of the performance period, by (B) the volume-weighted average share
price for the 30 trading days preceding the beginning of the performance period.
The second criterion is based on the Company's annual return on average capital
employed ("ROCE") for each year during the three-year performance period. The
split between the two performance criteria is even for the PSUs granted in 2018
and 2019, whereas the split is two-thirds weighted to the TSR criterion and
one-third weighted to the ROCE criterion for the PSUs granted in 2020.
Compensation expense associated with PSUs is recognized as general and
administrative expense over the performance period. Because these awards depend
on a combination of performance-based and market-based settlement criteria,
compensation expense may be adjusted in future periods as the number of units
expected to vest increases or decreases based on the Company's expected ROCE
performance.
The fair value of the PSUs was measured at the grant date. The portion of the
PSUs tied to the TSR required a stochastic process method using a Brownian
Motion simulation. A stochastic process is a mathematically defined equation
that can create a series of outcomes over time. These outcomes are not
deterministic in nature, which means that by iterating the equations multiple
times, different results will be obtained for those iterations. In the case of
the Company's TSRs, the Company could not predict with certainty the path its
stock price or the stock prices of its peers would take over the performance
period. By using a stochastic simulation, the Company created multiple
prospective stock pathways, statistically analyzed these simulations, and
ultimately made inferences regarding the most likely path the stock price would
take. As such, because future stock prices are stochastic, or probabilistic with
some direction in nature, the stochastic method, specifically the Brownian
Motion Model, was deemed an appropriate method by which to determine the fair
value of the portion of the PSUs tied to the TSR. Significant assumptions used
in this simulation include the Company's expected volatility, risk-free interest
rate based on U.S. Treasury yield curve rates with maturities consistent with
the performance period, as well as the volatilities for each of the Company's
peers.
Stock Options. We recognize compensation expense for all stock option awards
granted to employees. Stock-based compensation expense is measured at the grant
date based on the fair value of the award and is recognized as an expense on a
straight-line basis over the requisite service period, which is generally the
vesting period. The fair value of stock option grants is based on a
Black-Scholes Model. Stock-based compensation expense recorded for stock option
awards is included in general and administrative expenses on our accompanying
statements of operations.
Income taxes
Our provision for taxes includes both federal and state taxes. We record our
federal income taxes 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
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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 would be 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. During the ordinary course of business, there are
many transactions and calculations for which the ultimate tax determination is
uncertain. The actual outcome of these future tax consequences could differ
significantly from our estimates, which could impact our financial position,
results of operations, and cash flows.
We also account for uncertainty in income taxes recognized in the financial
statements in accordance with GAAP by prescribing a recognition threshold and
measurement attribute for a tax position taken or expected to be taken in a tax
return. Authoritative guidance for accounting for uncertainty in income taxes
requires that we recognize the financial statement benefit of a tax position
only after determining that the relevant tax authority would more likely than
not sustain the position following an audit. For tax positions meeting the
more-likely-than-not threshold, the amount recognized in the financial
statements is the largest benefit that has a greater than 50% likelihood of
being realized upon ultimate settlement with the relevant tax authority. We did
not have any uncertain tax positions as of the year ended December 31, 2020 .
Recent accounting pronouncements
Please refer to Part II, Item 8, Note 1 - Summary of Significant Accounting
Policies for additional details.
Effects of Inflation and Pricing
Inflation in the United States was 1.6% in 2020, 2.3% in 2019, and 2.2% in 2018.
These changes did not have a material impact on our results of operations for
the periods ended December 31, 2020 , 2019, and 2018. Although the impact of
inflation has been relatively insignificant in recent years, it is still a
factor in the United States economy, and we tend to experience inflationary
pressure on the cost of oilfield services and equipment as increasing oil and
gas prices increase drilling activity in our areas of operations. Material
changes in prices also impact the current revenue stream, estimates of future
reserves, borrowing base calculations, depletion expense, impairment assessments
of oil and gas properties, ARO, and values of properties in purchase and sale
transactions. Material changes in prices can impact the value of oil and gas
companies and their ability to raise capital, borrow money, and retain
personnel.
Off-Balance Sheet Arrangements
Currently, we do not have any off-balance sheet arrangements.
Item 7A. Quantitative and Qualitative Disclosures About Market Risks.
Oil and Natural Gas Price Risk
Our financial condition, results of operations, and capital resources are highly
dependent upon the prevailing market prices of oil and natural gas. These
commodity prices are subject to wide fluctuations and market uncertainties due
to a variety of factors that are beyond our control. Factors influencing oil and
natural gas prices include the level of global demand for oil and natural gas,
the global supply of oil and natural gas, the establishment of and compliance
with production quotas by oil exporting countries, weather conditions which
determine the demand for natural gas, the price and availability of alternative
fuels, local and global politics, and overall economic conditions. It is
impossible to predict future oil and natural gas prices with any degree of
certainty. Sustained weakness in oil and natural gas prices may adversely affect
our financial condition and results of operations, and may also reduce the
amount of oil and natural gas reserves that we can produce economically. Any
reduction in our oil and natural gas reserves, including reductions due to price
fluctuations, can have an adverse effect on our ability to obtain capital for
our exploration and development activities. Similarly, any improvements in oil
and natural gas prices can have a favorable impact on our financial condition,
results of operations, and capital resources. If oil and natural gas SEC prices
declined by 10%, our proved reserve volumes would decrease by 2% and our PV-10
value as of December 31, 2020 would decrease by approximately 27% or $117.6
million . If oil and natural gas SEC prices increased by 10%, our proved reserve
volumes would increase by 1% and our PV-10 value as of December 31, 2020 would
increase by approximately 27% or $119.3 million .
PV-10 is a non-GAAP financial measure. Please refer to Estimated Proved Reserves
under Part I, Item 1 of this Annual Report on Form 10-K for management's
discussion of this non-GAAP financial measure.
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Commodity Derivative Contracts
Our primary commodity risk management objective is to protect the Company's
balance sheet via the reduction in cash flow volatility. We enter into
derivative contracts for oil, natural gas, and natural gas liquids using NYMEX
futures or over-the-counter derivative financial instruments. The types of
derivative instruments that we use include swaps, collars, and puts.
Upon settlement of the contract(s), if the relevant market commodity price
exceeds our contracted swap price, or the collar's ceiling strike price, we are
required to pay our counterparty the difference for the volume of production
associated with the contract. Generally, this payment is made up to 15 business
days prior to the receipt of cash payments from our customers. This could have
an adverse impact on our cash flows for the period between derivative
settlements and payments for revenue earned.
While we may reduce the potential negative impact of lower commodity prices, we
may also be prevented from realizing the benefits of favorable price changes in
the physical market.
Presently, our derivative contracts have been executed with seven
counterparties, all of which are members of our Credit Facility syndicate. We
enter into contracts with counterparties whom we believe are well capitalized.
However, if our counterparties fail to perform their obligations under the
contracts, we could suffer financial loss.
Please refer to the Derivative Activities section of Part I, Item 1 of this
Annual Report on Form 10-K for summary derivative activity tables.
For the oil and natural gas derivatives outstanding at December 31, 2020 , a
hypothetical upward or downward shift of 10% per Bbl or MMBtu in the NYMEX
forward curve as of December 31, 2020 would decrease our derivative gain by
$14.2 million or increase it by $13.0 million , respectively.
Interest Rates
At both December 31, 2020 and on the filing date of this report, we had a zero
balance on our Credit Facility. Borrowings under our Credit Facility bear
interest at a fluctuating rate that is tied to an adjusted Base Rate or LIBOR,
at our option. Any increases in these interest rates can have an adverse impact
on our results of operations and cash flows. As of December 31, 2020 and through
the filing date of this report, the Company was in compliance with all financial
and non-financial covenants.
Counterparty and Customer Credit Risk
In connection with our derivatives activity, we have exposure to financial
institutions in the form of derivative transactions. Seven lenders under our
Credit Facility are counterparties on our derivative instruments currently in
place and have investment grade credit ratings.
We are also subject to credit risk due to concentration of our oil and natural
gas receivables with certain significant customers. The inability or failure of
our significant customers to meet their obligations to us or their insolvency or
liquidation may adversely affect our financial results. We review the credit
rating, payment history, and financial resources of our customers, but we do not
require our customers to post collateral.
Marketability of Our Production
The marketability of our production depends in part upon the availability,
proximity, and capacity of third-party refineries, access to regional trucking,
pipeline and rail infrastructure, natural gas gathering systems, and processing
facilities. We deliver crude oil and natural gas produced through trucking
services, pipelines, and rail facilities that we do not own. The lack of
availability or capacity on these systems and facilities could reduce the price
offered for our production or result in the shut-in of producing wells or the
delay or discontinuance of development plans for properties.
A portion of our production may also be interrupted, or shut in, from time to
time for numerous other reasons, including as a result of accidents, weather,
field labor issues or strikes, or we might voluntarily curtail production in
response to market conditions. If a substantial amount of our production is
interrupted at the same time, it could adversely affect our cash flow.
Currently, there are no pipeline systems that service wells in our French Lake
area of the Wattenberg Field. If neither we nor a third-party constructs the
required pipeline system, we may not be able to fully test or develop our
resources in French Lake .
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