SUNDANCE ENERGY INC. The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Part II, Item 8. "Financial Statements and Supplementary Data" of this annual report. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Part I, Item 1A. "Risk Factors" along with "Cautionary Statement Regarding Forward-Looking Statements" on page 2 of this annual report for information on the risks and uncertainties that could cause our actual results to be materially different from our forward-looking statements.
Overview and Executive Summary
We are an onshore independent oil and natural gas company focused on the development, production and exploration of large, repeatable resource plays inNorth America . Our operations are located in the Eagle Ford formation in southTexas . Our strategy is to acquire and/or develop assets where we are operator and have high working interests, positioning us to efficiently control the pace and scope of our development and the allocation of our capital resources. Serving as operator allows us to control the drilling, completion, operations, and marketing of sold volumes. As a result of the sharp decline in commodity price s during the first quarter of 2020 and the impact on our financial position, we significantly decreased our level of capital spending. Upon emergence from bankruptcy (described below under Recent Events), we plan to continue to focus on developing high-return assets from our portfolio, while preserving an attractive oil-rich inventory. Recent Events
On
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OnMarch 9, 2021 , we entered into a RSA with (i)Toronto Dominion (Texas) LLC , as agent pursuant to the Revolving Facility, (ii) the lenders party to that certain Credit Agreement, dated as ofJuly 18, 2018 (as amended, modified, or supplemented), (iii)Morgan Stanley Capital Administrators Inc. as agent pursuant to the Term Loan Facility, and (iv) the lenders party to that certain Amended & Restated Term Loan Credit Agreement, dated as ofApril 23, 2018 (as amended, modified, or supplemented from time to time) to support a reorganization in accordance with the terms set forth in the Plan. Due to the Chapter 11 Cases, the Company's common stock was delisted from NASDAQ onMarch 19, 2021 and began trading on the Pink Open market under the symbol "SNDEQ". We expect to continue operations in the normal course for the duration of the Chapter 11 Cases. To ensure ordinary course operations, we have obtained approval from theBankruptcy Court for certain "first day" motions, including motions to obtain customary relief intended to minimize the impact of the Chapter 11 Cases on our operations, customers and employees. Upon emergence from bankruptcy, we expect that we will no longer be a publicly traded company. For more information on the Chapter 11 Cases and related matters, please see Note 15-Subsequent Events in Part II, Item 8. "Financial Statements and Supplementary Data". Business and Industry Outlook During 2020, WTI oil spot prices ranged from a high of$63.27 in January and briefly dropped below zero inApril 2020 , primarily due to drastic price cutting and increased production bySaudi Arabia coupled with a demand reduction caused by the global COVID-19 pandemic. In the second half of 2020, WTI oil spot prices slowly rebounded and hovered near$40 per barrel. While market prices for crude oil, natural gas and NGLs are inherently volatile, the increase in supply and decrease in demand to historic extremes has impacted our entire industry. Given the dynamic nature of these macroeconomic conditions, we are unable to reasonably estimate the period of time that these market conditions will exist and the extent of the impact they will have on our business, liquidity, results of operations, financial condition, or the timing of any subsequent recovery. The sharp decline in commodity prices and lower expectations for near-term commodity prices, has reduced our revenue and cash flow from operations and slowed the pace at which we can develop our oil and natural gas assets. In addition, substantial and extended declines in oil, natural gas and NGL prices reduces the amount of oil and natural gas that we can produce economically, which has reduced our oil and gas reserve quantities and resulted, and may result, in impairment of our proved oil and gas properties (such as the impairment discussed under Results of Operations and Note 2). It has also impacted our ability to comply with certain financial covenants required by our credit facilities (as described further under Note 6). 48
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Year Ended
Revenues and Sales Volume. The following table provides the components of our
revenues for the years ended
Year ended
December 31,
Revenue (In $ '000s): 2020 2019 Change in $ Change as %
Oil sales $ 76,533 $ 177,853 $ (101,320) (57)
Natural gas sales 7,887 12,553 (4,666) (37)
NGL sales 7,392 13,174 (5,782) (44)
Product revenue $ 91,812 $ 203,580 $ (111,768) (55)
Year ended
December 31,
Net sales volumes: 2020 2019 Change in Volume Change as %
Oil (Bbls) 2,104,758 3,076,582 (971,824) (32)
Natural gas (Mcf) 3,969,000 5,767,779 (1,798,779) (31)
NGL (Bbls) 539,828 797,784 (257,956) (32)
Oil equivalent (Boe) 3,306,086 4,835,663 (1,529,577) (32)
Average daily sales volumes (Boe/d) 9,033 13,248 (4,215) (32)
Boe and average net daily production. Due to the significant decline in oil prices in early 2020 and capital spending limitations included in our recent credit agreements amendments, we scaled back our 2020 drilling program as compared to the development programs in 2019 and 2018 (which was back-loaded). As a result, sales volumes decreased by 1,529,577 Boe (4,215 Boe/d) to 3,306,086 Boe (9,033 Boe/d) for the year endedDecember 31, 2020 compared to 4,835,663 Boe (13,248 Boe/d). Production was higher in 2019 due to more wells coming onto production in late 2018 and early 2019 (11.0 new wells coming online in the fourth quarter of 2018 and 22.0 new operated wells in 2019) compared to late 2019 and 2020 (2.0 wells coming online in the fourth quarter of 2019 and 8.0 operated wells came online in 2020). The 2019 period included approximately 1,153 Boe/d of sales volume from theDimmit County assets, which were sold inOctober 2019 .
Our sales volume is oilweighted, with oil representing 64%
of total sales volume and liquids (oil and NGLs) representing 80% for both
the years ended
Oil sales. Oil sales decreased by$101.3 million (57%) to$76.5 million for the year endedDecember 31, 2020 from$177.9 million for the prior year. The decrease in oil revenue was driven by lower sales volumes ($56.2 million ), coupled with lower product pricing ($45.1 million ). The average realized price on the sale of our oil decreased by 37% to$36.36 per Bbl for the year endedDecember 31, 2020 from$57.81 per Bbl for the prior year. Oil sales volumes decreased 32% to 2,104,758 Bbls for the year endedDecember 31, 2020 compared to 3,076,582 Bbls for the prior year. Natural gas sales. Natural gas sales decreased by$4.7 million (37%) to$7.9 million for the year endedDecember 31, 2020 from$12.6 million for the prior year. The decrease in natural gas revenues was the result of lower sales volumes ($3.9 million ), combined with lower product pricing ($0.8 million ). Natural gas sales volumes decreased 31% to 3,969,000 Mcf for the year endedDecember 31, 2020 compared to 5,767,779 Mcf for the prior year. The average realized price on the sale of our natural gas decreased by 9% to$1.99 per Mcf (net of certain transportation and marketing costs) for the year endedDecember 31, 2020 from$2.18 per Mcf for the prior year. NGL sales. NGL sales decreased by$5.8 million (44%) to$7.4 million for the year endedDecember 31, 2020 from$13.2 million for the prior year. The decrease in NGL revenues was the result of lower sales volumes ($4.3 million ), combined with lower product pricing ($1.5 million ). NGL sales volumes decreased 257,956 Bbls (32%) to 539,828 Bbls for the year endedDecember 31, 2020 compared to 797,784 Bbls for the prior year. The average realized price on the sale of our NGLs decreased by 17% to$13.69 per Bbl for the year endedDecember 31, 2020 from$16.51 per Bbl for the prior year. 49
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The following table provides a summary of our operating expenses on a per BOE
basis:
Year ended December 31,
Selected per Boe metrics 2020 2019 Change
Total oil, natural gas and NGL revenues
(price received) $ 27.77 $ 42.10 $ (14.33)
Effect of commodity derivatives on
average price 15.25 2.29 12.96
Total oil, natural gas and NGL revenues (price realized)$ 43.02 $ 44.39 $ (1.37) Lease operating expense (1)$ (6.80) $ (5.85) $ (0.95) Workover expense (1)$ (0.82) $ (1.11) $ 0.29 Gathering, processing and transportation expense$ (6.15) $ (3.53) $ (2.62) Production taxes$ (1.65) $ (2.37) $ 0.72 Depreciation, depletion and amortization (2)$ (23.83) $ (18.96) $ (4.87)
General and administrative expense$ (6.70) $ (4.61)
$ (2.09)
(1) Lease operating expense and workover expense are included together in lease
operating and workover expenses on the consolidated statement of operations.
(2) Excludes depreciation related to corporate assets.
Lease operating expense. Our LOE decreased by$5.8 million (21%) to$22.5 million for the year endedDecember 31, 2020 from$28.3 million in the prior year, but increased$0.95 per Boe to$6.80 per Boe from$5.85 per Boe. InMarch 2020 , we made field operating changes and renegotiated pricing with a number of our vendors due to the material drop in market oil prices, which reduced our costs on an absolute basis. However, a significant portion of our costs are fixed, and the per Boe rate was negatively impacted by our lower production volumes. Workover expense. Our workover expenses decreased$2.7 million to$2.7 million for the year endedDecember 31, 2020 , as compared to$5.4 million for the year endedDecember 31, 2019 . Workover expense per Boe decreased$0.29 per Boe to$0.82 per Boe for the year endedDecember 31, 2020 as compared to the prior year. We have reduced workover expense through conversion of rod pumps to gas lift and redesign of certain rod pump wells to reduce our well failure rates and the associated workover expense going forward. In addition, as a result of the material drop in oil prices, beginningApril 2020 throughJuly 2020 , we deferred workovers for low producing wells as it was not economic to service the wells which drove down absolute and per Boe workover expense for the year endedDecember 31, 2020 . Gathering, processing and transportation expense ("GP&T"). GP&T increased by$3.3 million ($2.62 per Boe) to$20.3 million ($6.15 per Boe) for the year endedDecember 31, 2020 as compared to$17.1 million ($3.53 per Boe) for the year endedDecember 31, 2019 . GP&T fees are primarily incurred on production from the properties we acquired inApril 2018 . Approximately$12.4 million and$14.7 million of the GP&T expense was incurred in normal course under various midstream agreements for the years endedDecember 31, 2020 and 2019, respectively, and the remainder of the expense was related to MRC shortfalls, as discussed below. Sales volumes from the acquired assets subject to these midstream agreements decreased 20% in 2020 as compared to 2019. Certain of our midstream agreements contain MRCs related to fees due on oil, natural gas and NGL volumes gathered, processed and/or transported. Under the terms of the contracts, if we fail to pay fees equal to or greater than the MRC under any of the contracts, we are required to pay a deficiency payment equal to the shortfall. Our MRC commitment totaled$21.8 million and$15.8 million for the years endedDecember 31, 2020 and 2019, respectively. The shortfall totaled$8.0 million ($2.42 per Boe) and$2.3 million ($0.49 per Boe) for the years endedDecember 31, 2020 and 2019, respectively. The increase in the shortfall year over year was the result of the lower production volumes due largely to the scaled-back development program. 50
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Production taxes. Our production taxes decreased by$6.0 million (53%) to$5.4 million for the year endedDecember 31, 2020 from$11.5 million for the prior year, which was driven by our overall decrease in revenue. Production taxes were 5.9% and 5.6% of total revenue for the year endedDecember 31, 2020 and 2019. During 2020, we recorded a severance tax refund related to prior periods of$1.1 million that the Company expects to receive in 2021. This was offset by higher ad valorem taxes. Ad valorem tax assessments are calculated by the taxing authorities usingJanuary 1 commodity pricing. The significant decline in pricing from the beginning of 2020, resulted in the ad valorem as a percentage of revenue for 2020 being higher than the statutory rates applied in the assessment of taxable value at the beginning of the year. Depletion, depreciation and amortization expense ("DD&A"). Our DD&A expense related to proved oil and natural gas properties decreased by$12.9 million (14%) to$78.8 million for the year endedDecember 31, 2020 from$91.7 million for the prior year. On a per Boe basis, DD&A increased to$23.83 per Boe for the year endedDecember 31, 2020 compared to$18.96 per Boe in 2019 primarily due to downward revisions to our proved developed reserves as a result of lower pricing and lower proved undeveloped reserves resulting from changes to our development program. This was partially offset by lower fourth quarter of 2020 DD&A due to the significant impairment in the third quarter 2020, which reduced the carrying value of proved oil and gas properties. Impairment expense. We recorded impairment expense of$331.9 million and$10.0 million for the years endedDecember 31, 2020 and 2019, In the third quarter of 2020, we identified an impairment triggering event for our proved oil and gas properties due to the adverse change to our business climate resulting from oil and gas prices declining in 2020 and the resulting changes in our future development plan. As such, we performed a quantitative assessment as ofSeptember 30, 2020 , and the estimated undiscounted cash flows from our proved properties were less than the carrying value of our oil and gas properties, which required us to record an impairment. During the year endedDecember 31, 2019 , we recorded impairment expense of$10.0 million related to ourDimmit County oil and gas properties, which were divested inOctober 2019 . General & Administrative expense ("G&A"). G&A decreased by$0.1 million (1%) to$22.1 million for the year endedDecember 31, 2020 as compared to$22.3 million for the prior year. During the year endedDecember 31, 2020 we incurred legal and advisory fees of$7.7 million ($2.32 per Boe) related to credit facility amendments and debt restructuring described previously, and$0.5 million ($0.14 per Boe) of restructuring costs associated with our workforce reduction in the second quarter. During 2019, we incurred one-time costs, primarily legal and accounting fees, to complete our redomiciliation to theU.S of$2.7 million ($0.55 per Boe). G&A, excluding the costs associated with these discrete transactions, decreased on an absolute basis as compared to prior year primarily due to lower salaries and wages as a result of the expected PPP loan forgiveness of$1.9 million and our workforce and salary reductions. As described under Credit Facilities, our G&A for the second and third quarter of 2020, was limited to$3 million per quarter and the fourth quarter was limited to$3.6 million (as defined in the agreements). After the adjustments provided for in the agreements, we were in compliance with the covenant for
these periods.
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Gain/loss on commodity derivative financial instruments. Our commodity
derivative contracts are marked to market at the end of each reporting period
with the changes in fair value being recognized as gain (loss) on commodity
derivative financial instruments, net. Cash flow, however, is only impacted by
the monthly settlements paid to or received by the counterparty, which are also
recorded as gain(loss) on commodity derivative financial instruments, net. The
components of gain (loss) on commodity derivative financial instruments was
as
follows (in thousands):
Year Ended December 31,
Gain (loss) on commodity derivative
financial instruments, net 2020 2019 $ Change
Unrealized gains (losses) $ 1,803 $ (31,637) $ 33,440
Realized gains (1) 50,429 11,095 39,334
Total $ 52,232 $ (20,542) $ 72,774 The realized gains for the years ended
(1) proceeds of
before their contractual maturity.
Interest expenses, net of amounts capitalized. The components of interest expense, net of amounts capitalized was as follows (in thousands):
Year ended December 31,
Interest Expense 2020 2019 Change in $ Change as %
Interest expense on Term Loan, Revolving
Facility and other $ 31,990 $ 32,720 $ (730) (2)
Amortization of debt issuance costs 3,707 3,351 356 11
Expense incurred with debt modification 1,199 - 1,199 100 Loss on interest rate swap 3,324 4,270 (946) (22) Capitalized interest (711) (2,283) 1,572 (69) Total$ 39,509 $ 38,058 $ 1,451 4 The decrease in interest expense on our Term Loan, Revolving Facility and other for the year endedDecember 31, 2020 was driven by the decrease in the average market interest rates, partially offset by an increase in the amount of outstanding debt and additional 2% of paid-in-kind ("PIK") interest, which is added to the principal of the Term Loan. The PIK interest, effectiveMay 30, 2020 , was added as part of the third amendment to the Term Loan inJune 2020 , and totaled$3.0 million for year endedDecember 31, 2020 , respectively. Our weighted average debt outstanding during 2020 was$371 million (excluding the impact of PIK) versus$347 million for 2019. AtDecember 31, 2020 , the stated weighted average interest rates on the Revolving Facility and the Term Loan were 7.40% (including default interest of 2%) and 11.00% (including 2% PIK interest added to the principal at each reporting period), respectively, as compared to 4.75% and 10.11%, atDecember 31, 2019 . Default interest of 2% was added to the Term Loan interest rate beginning inJanuary 2021 . As described in Note 6 to our Conslidated Financial Statements, we entered into the fourth amendment to our Revolving Facility inJanuary 2020 , which among other things, appointedToronto Dominion (Texas) LLC , as the administrative agent (replacing Natixis). As a result of the former administrative agent exiting the facility and terminating its commitments, we wrote-off previously capitalized deferred debt issuance costs of$1.1 million during 2020 in accordance with Accounting Standards Codification 470 - Debt. We capitalized new financing and legal fees of$1.0 million , which will be amortized over the remaining loan term. InJune 2020 , we entered into the fifth amendment to our Revolving Facility, which among other things, reduced our borrowing base from$210 million to$170 million . As a result, we wrote-off deferred debt issuance costs in proportion to the decrease in borrowing base of$0.1 million . 52 Table of Contents We recognized a loss on our interest rate swap of$3.3 million and$4.3 million for the years endedDecember 31, 2020 and 2019, respectively. Our interest rate swaps are marked to market at the end of each reporting period, with the changes in fair value being recognized as interest expense. Cash settlements paid to or received by our counterparty are also recorded as interest expense. In 2020, the loss on the interest rate swap consisted of$5.8 million of unrealized gains and$9.1 million of realized cash settlements, which included payments to unwind all of the outstanding swap positions inDecember 2020 . In 2019, the loss on the interest rate swap consisted of$3.6 million of unrealized losses and$0.6 million of realized cash settlements.
Income Tax Benefit. The components of our provision for income tax benefit and our effective income tax rates were as follows (in thousands):
Year ended December 31,
Income tax benefit 2020 2019 Change in $
Current tax benefit $ (85) $ - $ (85)
Deferred tax benefit (6,916) (4,518) (2,398)
Total income tax benefit $ (7,001) $ (4,518) $ (2,483)
Effective tax rate 1.9% 10.2%
Our effective income tax rate, as shown above, differs from the statutory rate (21%) primarily due to our valuation allowance. See Note 8 Part II, Item 8. "Financial Statements and Supplementary Data"to the consolidate financial statements for more information.
Other income (expense). During the year endedDecember 31, 2020 , we conveyed our non-core interest in the petroleum exploration license 570 located in theCooper Basin inAustralia ("PEL570") to the property's operator. At the time of the conveyance, we had accrued expenses related to exploratory drilling of approximately$3.7 million . As consideration for the property, the operator settled our outstanding liability for$0.9 million . The property had previously been fully impaired, and therefore we recognized a gain on the conveyance of$2.7 million . As a result of the conveyance, we were also relieved of our commitment to fund any further exploratory drilling for PEL570. In 2019 other income (expense) was primarily comprised of expense of$0.7 million for a litigation settlement related to a historical sale of non-operatedNorth Dakota properties in 2013 and expense of$0.9 million for early termination of our drilling rig. Adjusted EBITDAX. Management has historically used both GAAP and certain non-GAAP measures to assess our performance. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by our management and certain external users of our consolidated financial statements, such as investors, industry analysts and lenders. We define "Adjusted EBITDAX" as earnings before interest expense, income taxes, DD&A, property impairments, gain/(loss) on sale of non-current assets, exploration expense, stock-based compensation, gains and losses on commodity hedging, net of settlements of commodity hedging and certain other non-cash or non-recurring income/expense items. Our management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance, identify operating trends (which may otherwise be masked by the excluded items) and compare the results of our operations from period to period without regard to our financing policies and capital structure. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP, or as an indicator of our operating performance or liquidity. 53 Table of Contents Year EndedDecember 31 ,
Reconciliation of Net Loss to Adjusted EBITDAX 2020
2019
Net loss$ (370,462) $ (39,590) Add back: Current and deferred income tax benefit (7,001) (4,518) Interest expense 39,509 38,058 (Gain) loss on commodity derivative financial instruments, net (52,232) 20,542 Settlement of commodity derivatives financial instruments 50,428 11,094 DD&A 79,582 92,334 Impairment expense 331,877 9,990 Exploration expense 193 337
Noncash stock-based compensation expense 280 504 Transaction-related expenses included in G&A expense (1) 7,852 2,677 Reduction-in-force related expenses included in G&A expense 476 - Other expense (income), net (2) (2,739) 769 Adjusted EBITDAX$ 77,763 $ 132,197
In 2019 and early 2020, we incurred one-time costs, primarily legal and
accounting fees, to complete our Redomiciliation to
(1) 2020, we incurred costs to amend our credit facilities, explore transactions
to reduce our leverage (as required by the third, fourth and fifth amendments
to the Term Loan) and complete the RSA.
In 2020, other expense (income), net included a
(2) conveyance of PEL570 to the operator. In 2019, other items of expense, net
was primarily related to litigation settlement expense of
Liquidity and Capital Resources
Overview OnDecember 31, 2020 , our cash balance totaled$5.3 million and we had a working capital deficit of$21.5 million (exclusive of the current classification of debt).
Our liquidity is highly dependent on prices we receive for the sale of oil, gas, and NGLs we produce. Prices we receive are determined by prevailing market conditions and greatly influence our revenue, cash flow, profitability, ability to comply with financial and other covenants in our credit facilities, access to capital and future rate of growth. We maintain a portfolio of derivative positions to help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. At times, we may choose to liquidate derivative positions before the contract ends in order realize the current value of our existing positions, to the extent permitted by our credit facilities. As of the date of this report, we had had oil derivatives in place covering an average of 3,142 Bbls per day for remainder of 2021 at a weighted average floor price of$48.16 . Please see Note 9 to our Consolidated Financial Statements included in Part II, Item 8. "Financial Statements and Supplementary Data" of this annual report for a summary of our outstanding derivative positions as ofDecember 31, 2020 .
Chapter 11 Cases and Effect of Automatic Stay
OnMarch 9, 2021 , we field for relief under Chapter 11 of the Bankruptcy Code. The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under our Revolving Facility and Term Loan, resulting in the automatic and immediate acceleration of all of our debt outstanding. Any efforts to enforce payment obligations related to the acceleration of our debt have been automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors' rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. Also onMarch 9, 2021 , we entered into a RSA with the Revolving Facility and Term Loan lenders to support a reorganization in accordance with the term set forth therein. As more fully described in Note 15 Subsequent Events, the Plan and the RSA contemplate a reorganization which would provide for the treatment of holders of certain claims and existing equity
interests.
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We expect to continue operations in the normal course for the duration of the
Chapter 11 Cases. To ensure ordinary course operations, we have obtained
approval from the Bankruptcy Court for certain "first day" motions to continue
our ordinary course operations after the filing date. In addition, we have
obtained a new up to $50 million DIP Facility to fund operations during
bankruptcy proceedings. For the duration of our Chapter 11 proceedings, our
operations and our ability to develop and execute our business plan are subject
to a high degree of risk and uncertainty associated with our Chapter 11 Cases.
The outcome of the Chapter 11 Cases is dependent upon factors that are outside
of our control, including actions of the Bankruptcy Court and our Lenders. The
significant risks and uncertainties related to our liquidity and Chapter 11
Cases described above raise substantial doubt about our ability to continue as a
going concern. There can be no assurance that we will confirm and consummate the
Plan as contemplated by the RSA or complete another plan of reorganization with
respect to the Chapter 11 Cases. As a result, we have concluded that our plans
do not alleviate substantial doubt about our ability to continue as a going
concern.
Sources of Liquidity and Capital Resources
Historically, our primary sources of liquidity have been borrowings under our credit facilities, cash flow from operations, and strategic dispositions of non-core oil and gas properties. From time to time, we have also raised additional equity from investors. Our primary use of capital has been for the acquisition and development of oil and natural gas properties. AtDecember 31, 2020 , we had outstanding borrowings on our Term Loan of$253.0 million (including PIK) and$130.6 million on the Revolving Facility. We were not in compliance with certain of the covenants of the Term Loan and Revolving Facility our credit facilities atDecember 31, 2020 . As described above, the commencement of the Chapter 11 Cases subsequent to yearend, resulted in an automatic and immediate acceleration of all of our debt outstanding. We also have other contractual commitments, which are described in Note 14-Commitments and Contingencies in Part II, Item 8 Financial Statements.
With cash on hand and cash flow from operations combined with the up to
Cash Flows Our cash flows for the years endedDecember 31, 2020 and 2019 are as follows: Year ended December 31, (In $ '000s) 2020 2019
Net cash provided by operating activities
Cash flows provided by operating activities. Cash provided by operating activities for the year endedDecember 31, 2020 was$33.1 million , a decrease of$78.2 million compared to the prior year ($111.2 million ). Including the effect of derivative settlements, including unwound positions, (as shown on page 50), our realized price per Boe decreased 3% to$43.02 per Boe as compared to$44.39 per Boe. During 2020, we had cash settlements from our derivative contracts of$49.84 million . Despite the relatively small decrease in realized price, our sales volume decreased by 32%, resulting in a significant decrease in operating cash flow. In addition, we had higher cash flows for G&A expenses due to costs incurred to restructure our debt. This was partially offset by the receipt of$1.9 million of PPP proceeds, which we expect to be forgiven. Due to payment timing, our cash flows from operations for the year endedDecember 31, 2019 included three quarterly interest payments on our Term Loan, whereas the year endedDecember 31, 2020 included four quarterly interest payments, which resulted in higher cash flows in 2019 of$6.5 million . In addition, we paid$6.3 million to unwind our interest rate swaps inDecember 2020 . Cash flows used in investing activities. Cash used in investing activities for the year endedDecember 31, 2020 decreased to$54.5 million as compared to$150.0 million in prior year. In 2020 and 2019, net cash flows used in investing activities was primarily for development of proved properties ($54.2 million and$166.7 million , respectively). In 2019, this was partially offset by the sale of ourDimmit County, Texas , oil and gas assets inOctober 2019 ($17.3 million ). See Capital Expenditures below for additional information regarding our investment in oil and gas properties. 55
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Cash flows provided by financing activities. Cash provided by financing activities for the year endedDecember 31, 2020 decreased to$14.3 million as compared to$49.6 million for the year endedDecember 31, 2020 . We drew$17.0 million on the Revolver in the third quarter of 2020 to meet our working capital needs. This was partially offset by a$1.4 million required repayment made in earlyJuly 2020 after we unwound a derivative position. InJanuary 2020 , we paid lender and legal fees totaling$1.0 million to amend our Revolving Facility to increase the borrowing base to$210 million (which was subsequently reduced to$170 million following the industry downturn). During 2019, we borrowed$50.0 million on our Revolving Facility to fund a portion of our 2019 drilling program. Capital Expenditures
The following table summarizes our capital expenditures incurred (excluding
changes related to our asset retirement obligation) for the years ending
Year ending December 31
(In $ '000s) 2020 2019 Change in $ Change in %
Unproved $ (15) $ 177 (192) (108)
Proved 40,925 149,766 (108,841) (73)
Total $ 40,910 $ 149,943 (109,033) (73)
Our capital expenditures for proved properties for the year endedDecember 31, 2020 decreased 73% to$40.9 million , as compared to$149.8 million in the prior year as a result of our scaled back development plan in light of commodity prices and our financial condition. In addition, the third, fourth and fifth amendments to the Term Loan and fifth amendment to the Revolving Facility limited our capital expenditures (as defined in the agreements) to$5 million for the periodMay 1, 2020 throughSeptember 30, 2020 , and to$11.1 million for the periodMay 1, 2020 throughDecember 31, 2020 . We were in compliance with these limits. In 2020, our drilling and completion costs totaled$34.8 million , which included costs to add 8.2 net producing wells, which were turned to sales inFebruary 2020 (2.0 net operated wells) lateJune 2020 (4.0 net operated wells) and December (2.0 net operated wells). We also invested$2.2 million into shared facility projects and$2.2 million for artificial lift and other well enhancements on existing wells. In 2019, our drilling and completion costs totaled$125.0 million , which included costs to add 22.3 net producing wells and there were 2.0 additional net operated wells waiting on completion and 0.3 non operated wells in the process of being drilled. In addition, we invested$13.6 million into shared facility projects during the year endedDecember 31, 2019 . Credit Facilities We and our wholly owned subsidiary, SEI, are parties to the Term Loan, which is a syndicated$250.0 million second lien term loan withMorgan Stanley Capital Administrators Inc. , as administrative agent, and the Revolving Facility, which is a syndicated reserve-based revolver withToronto Dominion (Texas) LLC , as administrative agent. As ofDecember 31, 2020 , we had a borrowing base of$190.0 million , elected commitment of$170 million ,$130.6 million of borrowings outstanding and$16.4 million of letters of credit in place under the Revolving Facility. As a result of the commencement of the Chapter 11 Cases, the lender's commitments under the Revolving Facility have been terminated. We are therefore unable to make additional borrowings or issue additional letters of credit
under the Revolving Facility. EffectiveJanuary 2021 , interest on the Revolving Facility accrued at a rate equal to Prime plus a margin, ranging from 1.50% to 2.50%, depending on the level of funds borrowed, plus post-default interest of 2%. The default interest rate was in place fromDecember 18, 2020 throughMarch 9, 2021 . Interest on the Term Loan accrues at LIBOR (with a LIBOR floor of 1.0%) plus 10.0%, of which 2% of the applicable margin is payable-in-kind (effectiveMay 30, 2020 ). BeginningJanuary 2021 , an additional post-default interest rate of 2% began to accrue on the Term Loan. 56 Table of Contents
During the Chapter 11 Cases, we expect the DIP Facility will fund a portion of our cash requirements. Interest on the DIP Facility will accrue at a rate equal to LIBOR (with a LIBOR floor of 1.0%) plus 8%. The DIP Facility agreement includes conditions precedent, representations and warranties, affirmative and negative covenants, and events of default customary for financings of this type and size. The DIP Facility will mature on the date which is the earliest of (a)June 14, 2021 , (b) the effective date of the Prepackaged Plan or (c) the date all DIP Facility loans become due and payable, whether by acceleration or otherwise. We made an initial draw of$10 million under the DIP Facility inMarch 2021 . We may make additional draws of up to$35 million during the Chapter 11 Cases. An additional$5 million in DIP Facility loans is available with consent of the DIP Facility lenders.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements that have, or are reasonably likely to have, a current or future effect on our financial statements, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
Critical Accounting Policies and Estimates
Our 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 GAAP. The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in our financial statements. Actual results could differ from our estimates and assumptions, and these differences could result in material changes to our financial statements. The following discussion presents information about our most critical accounting policies and estimates. Our significant accounting policies are further described in Note 1 to our audited consolidated financial statements included in "Item 8. Financial Statements and Supplemental Data" of this annual report. Estimates of Oil and Gas Reserve Quantities. The estimated quantities of oil, natural gas and NGL reserves are integral to the calculation of DD&A and to assessments of possible impairment of assets. Discounted future net cash flows derived from our reserve estimates were also utilized in calculating the fair value of our oil and natural gas for the write-down of proved properties in the third quarter of 2020. Proved oil and gas reserves are 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. These estimates require significant judgements to be made regarding future development and production costs, development plans and fiscal regimes. The estimates of reserves may change from period to period as the economic assumptions used to estimate the reserves can change from period to period and as additional geological data is generated during the course of operations.Ryder Scott prepared 100% of our proved reserve estimates as ofDecember 31, 2020 and 2019. In connection withRyder Scott performing their independent reserve estimations, we furnish them with the following information that they review: (i) technical support data, (ii) technical analysis of geologic and engineering support information, (iii) economic and production data and (iv) our well ownership interests and (v) expected future development plans. Depreciation, Depletion and Amortization. The quantities of estimated proved oil and gas reserves are a significant component of our calculation of DD&A expense, and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserve quantities were revised upward or downward, net income would increase or decrease, respectively. 57 Table of Contents DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for proved leasehold acquisition costs is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. We have one unit-of-production field, the Eagle Ford formation. This method considers the geographic concentration, operating similarities within the area, geologic considerations and common cost environments in this area. Proved Property Impairment. We assess our proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. We estimate the expected future cash flows of our oil and gas properties and compare these undiscounted cash flows to the carrying value of the oil and gas properties to determine if the carrying value is recoverable. We may apply an additional risk-adjustment factor to the undiscounted cash flows from proved undeveloped reserves. If the carrying value exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, estimated future operating costs, and discount rates commensurate with the risk associated with realizing the projected cash flows. Our impairment analysis requires us to apply judgment in identifying impairment indicators and estimating future cash flows of our oil and gas properties. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may incur impairment expense. For 2020, the pricing used in our internal estimate of future cash flows was based on WTI strip prices for the first 24 months, with the price escalating up to a terminal price of$50 in year five and forward. As a result of lower commodity prices atSeptember 30, 2020 and the resulting impact on our estimated future cash flows, the carrying costs of our proved property exceeded our estimated cash flows and we recognized impairment expense of$331.8 million . Following theSeptember 30, 2020 impairment and largely due to the increase in WTI strip pricing atDecember 31, 2020 , our expected undiscounted future cash flows exceeded the carrying value of our proved oil and gas properties. Unproved Property Impairment. Unproved properties consist of costs incurred to acquire undeveloped leases as well as purchases of unproved reserves. Undeveloped lease costs and unproved reserve acquisitions are initially capitalized, and when successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. We evaluate significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, or future plans to develop acreage. Derivative Financial Instruments. We use derivative financial instruments to mitigate our exposure to changes in commodity prices arising in the normal course of business. We primarily utilize commodity price swap, option and costless collar contracts. We do not trade in derivative financial instruments for speculative purposes. None of our derivative contracts have been designated as cash flow hedges for accounting purposes, and as a result, all of our derivative contracts are recorded in the consolidated financial statements at fair value, with changes in derivative fair value being recognized currently in earnings.
We determine the recorded amounts of our derivative instruments measured at fair
value utilizing third-party valuation specialists, who utilize industry-standard
models that consider various assumptions, including quoted forward prices for
commodities, time to maturity, volatility and credit risk. We review these
valuations, including the related model inputs and assumptions, and analyze
changes in fair value measurements between periods. We corroborate such inputs,
calculations and fair value changes using various methodologies, and review
unobservable inputs for reasonableness utilizing relevant information from other
published sources. We also utilize counterparty valuations to assess the
reasonableness of our valuations. The values we report in our financial
statements change as the assumptions used in these valuations are revised to
reflect changes in market conditions (particularly those for oil and natural gas
forward prices) or other factors, many of which are beyond our control.
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Income Taxes. We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in predicting when these events may occur and whether recovery of an asset is more likely than not, including judgments and assumptions about future taxable income and future operating conditions (particularly as related to prevailing oil and natural gas prices). For the year endedDecember 31, 2020 , we did not recognize tax assets of$139.7 million as the recovery was not determined to be more likely than not. Some or all of these deferred tax assets could be recognized in future periods against future taxable income. Additionally, our federal and state income tax returns are generally not filed before the consolidated financial statements are prepared. Therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating and capital loss carryforwards and carrybacks. Adjustments related to differences between the estimates we use and actual amounts we report are recorded in the periods in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery and liability settlement could have an impact on our results of operations. Revisions to our estimated effective tax rate could increase or decrease our reported income tax expense or benefit. Our effective and statutory income tax rates could be impacted by the state income tax rates in which we operate, and the effective and statutory income tax rates are not significantly different as the amount of permanent differences resulting from treatment that differs for assets and liabilities for financial and tax reporting purposes is not significant. The tax impact of temporary differences, primarily oil and gas properties, is reflected in deferred income taxes. AtDecember 31, 2020 and 2019, we had no unrecognized tax benefits that would impact our effective tax rate and we have not provided for interest or penalties related to uncertain tax positions. Revenue Recognition. Our revenue is derived from the sale of produced oil, natural gas and NGLs. Revenue is recorded in the month the product is delivered to the purchaser, while payment is received up to 60 days after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received. Historically the differences have not been material. Transfer of control drives the statement of operations classification of transportation, gathering, processing, and marketing expenses ("fees and other deductions") within the accompanying statements of operations. Fees and other deductions incurred prior to control transfer are recorded within gathering, processing and transportation expense line item on the accompanying statements of operations, while fees and other deductions incurred subsequent to control transfer are recorded as a reduction of revenue.
Recently Issued Accounting Pronouncements. See Note 1 to our Consolidated Financial Statements included in Part II, Item 8. "Financial Statements and Supplementary Data" of this annual report for discussion of the recent accounting pronouncements.
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