Item 7. Management’s Discussion and Analysis
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with the historical financial statements and related notes included elsewhere in this Report. This discussion contains “ forward ‑ looking statements ” reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward ‑ looking statements due to a number of factors. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this report. Please read Cautionary Note Regarding Forward ‑ Looking Statements. Also, please read the risk factors and other cautionary statements described under “ Part I, Item 1A. Risk Factors. ” We assume no obligation to update any of these forward ‑ looking statements, except as required by applicable law.
Overview
HighPeak Energy, Inc., a Delaware corporation, was formed in October 2019 solely for the purpose of combining the businesses of Pure and HPK LP, referred to herein as the “HighPeak business combination,” which was completed on August 21, 2020. HPK LP was formed in August 2019 for the purpose combining the assets of HighPeak I and HighPeak II into one entity. HighPeak I was formed in June 2014 for the purpose of acquiring, exploring and developing oil and natural gas properties, although it had no activity until 2017. Beginning in late 2017, HighPeak I began acquiring its assets through an organic leasing campaign and a series of acquisitions consisting primarily of leasehold acreage and existing vertical producing wells.
The Company’s assets are located primarily in Howard County, Texas, which lies within the north eastern part of the oil-rich Midland Basin. As of December 31, 2020, the assets consisted of two highly contiguous leasehold positions of approximately 59,092 gross (50,636 net) acres, approximately 24% of which were held by production, with an average working interest of 86%. Approximately 97% of the operated acreage provides for horizontal wells with lateral lengths of 10,000 feet or greater. For the year ended December 31, 2020, approximately 95% and 5% of production from the assets were attributable to liquids (both oil and NGL) and natural gas, respectively. As of December 31, 2020, HighPeak Energy was drilling with one (1) rig. We are the operator on approximately 95% of the net acreage across our assets. Further, as of December 31, 2020, there were approximately 115 gross (71.7 net) producing wells, including 19 gross (18.3 net) horizontal wells, with total sales volumes of approximately 3,426 Boe/d in December 2020. As of December 31, 2020, of the 22,515 MBoe of proved reserves of the assets, 46% were developed, 94% of which were liquids.
The financial results as presented in this section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” consist of the historical results of HPK LP from August 28, 2019 (Inception) through December 31, 2019 combined with HighPeak I for the year ended December 31, 2019 (excluding HighPeak I’s equity in losses of HPK LP which was its only activity during the period following its business combination with and into HPK LP), HPK LP for the period from January 1, 2020 through August 21, 2020 and the Company from August 22, 2020 through December 31, 2020. At the Closing of the HighPeak business combination on August 21, 2020, the Company’s “predecessors” for accounting purposes were HPK LP for the period from October 1, 2019 through August 21, 2020 and HighPeak I from January 1, 2017 through September 30, 2019 (collectively, the “Predecessors”).
Outlook
HighPeak Energy’s financial position and future prospects, including its revenues, operating results, profitability, liquidity, future growth and the value of its assets, depend primarily on prevailing commodity prices. The oil and natural gas industry is cyclical and commodity prices are highly volatile. For example, during the period from January 1, 2018 through December 31, 2020, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $16.70 to a high of $70.76, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.50 to a high of $4.72. For the month of April 2020, the calendar month average NYMEX WTI crude oil price was $16.70 per Bbl and the last trading day NYMEX natural gas price was $1.63 per MMBtu. Due to the absence of any debt, the Company has not historically entered into any hedges. With the addition of the Revolving Credit Facility in December 2020, HighPeak Energy will be required to enter into hedging arrangements during the first quarter of 2021.
Impact of the COVID-19 Pandemic and 2020 Plan Changes
The COVID-19 pandemic has resulted in a severe worldwide economic downturn, significantly disrupting the demand for oil and natural gas throughout the world, and has created significant volatility, uncertainty and turmoil in the oil and gas industry. The decrease in demand for oil combined with pressures on the global supply-demand balance for oil and related products, resulted in oil prices declining significantly beginning in late February 2020. The length of this demand disruption is unknown, and there is significant uncertainty regarding the long-term impact to global oil demand, which will ultimately depend on various factors and consequences beyond the Company's control, such as the duration and scope of the pandemic, the length and severity of the worldwide economic downturn, the ability of OPEC, Russia and other oil producing nations to manage the global oil supply, additional actions by businesses and governments in response to the pandemic, the economic downturn and the decrease in oil demand, the speed and effectiveness of responses to combat the virus, and the time necessary to balance oil supply and demand to restore oil pricing. In response to these developments, the Company has implemented measures to mitigate the impact of the COVID-19 pandemic on its employees, operations and financial position. These measures include, but are not limited to, the following:
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Employee Safety. The Company has taken steps to keep its employees safe during the COVID-19 pandemic by implementing preventative measures and developing response plans intended to minimize unnecessary risk of exposure and infection among its employees. The Company has also modified certain business practices (including those related to non-operational employee work locations, such as a significant reduction in physical participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, and other governmental and regulatory authorities.
Expense Management. With the reduction in revenue, the Company has implemented, and will continue to evaluate other cost saving initiatives, including:
•
Continuing to optimize drilling, completion and operational efficiencies, resulting in lower operating costs per unit of production.
•
Reducing annual general and administrative and other overhead related costs through various cost reduction efforts across the organization.
Balance Sheet, Cash Flow and Liquidity. The Company has taken the following actions to strengthen its financial position and increase liquidity:
•
Maintained a debt free balance sheet and pursued increased liquidity by adding a credit facility with a modest borrowing base at attractive interest rates.
•
Poised to use derivative positions to reduce the effects of oil price volatility on its net cash provided by operating activities.
The Company continues to assess the global impacts of the COVID-19 pandemic and may modify its plans as the health and economic impacts of COVID-19 continue to evolve.
Financial and Operating Performance
The Company's financial and operating performance for the period from August 22, 2020 through December 31, 2020 plus the period from January 1, 2020 through August 21, 2020 of its Predecessors included the following highlights:
•
Net loss attributable to common stockholders for the period from August 22, 2020 through December 31, 2020 was $16.4 million ($0.18 per diluted share) plus the net loss of the Company’s Predecessor for the period from January 1, 2020 through August 21, 2020 of $85.0 million compared with a net loss of the Company’s Predecessors of $11.6 million for the year ended December 31, 2019. The primary components of the $89.9 million decrease in earnings attributable to common stockholders include:
•
a $76.5 million charge to expense related to an acquisition that was terminated in April 2020 primarily attributable to the downturn in oil prices related to COVID-19 whereby the Company had paid a $61.5 million nonrefundable deposit during 2019 plus a $15 million extension payment paid in 2020 that was also nonrefundable;
•
a $15.8 million increase in stock-based compensation expense primarily attributable to $15.5 million in stock-based compensation related to stock options that were granted in August 2020 upon the closing of the HighPeak business combination whereby approximately 75% of the stock options vested immediately causing a charge to earnings plus 62,500 shares of non-restricted stock issued to our non-management directors in November 2020 totaling $302,000 in stock-based compensation expense;
•
a $12.0 million increase in depletion, depreciation and amortization expense due to a 317% increase in overall sales volumes, partially offset by an 8% decrease in the depletion, depreciation and amortization rate from $25.04 to $23.08 per Boe, both as a result of increased proved reserves due to the Company’s successful horizontal drilling program in the Permian Basin;
•
a $5.2 million increase in production costs, including taxes, primarily attributable to the 317% increase in sales volumes as a result of the Company’s successful horizontal drilling program in the Permian Basin partially offset by 23% lower taxes on a dollar per Boe basis due to lower overall realized prices of 26%; and
•
a $2.2 million increase in exploration and abandonment expenses related to the impairment of $4.8 million during 2020 related to various undeveloped leasehold costs that the Company was not successful in obtaining extensions on, partially offset by lower geophysical data purchases of almost $2.6 million that were incurred in 2019;
partially offset by:
•
a $16.5 million increase in oil and gas revenues due to a 317% increase in daily sales volumes due to the Company’s successful horizontal drilling program in the Permian Basin, partially offset by a 27% decrease in average realized commodity prices per Boe;
•
a $4.2 million increase in the Company's income tax benefit due to the net loss experienced in 2020 and the fact that the Predecessors were pass through entities for income tax purposes and did not recognize any tax expense or benefit on their financial statements; and
•
a $1.1 million decrease in general and administrative costs due primarily to a significant amount of expenses relating to the HighPeak business combination that were incurred during 2019 plus various cost reduction efforts implemented across the organization during 2020 in response to the COVID-19 pandemic and downturn in crude oil prices, partially offset by increased costs in late 2020 associated with being a public company.
53
•
During the period from August 22, 2020 through December 31, 2020, average daily sales volumes totaled 3,292 Boe/d and during the period from January 1, 2020 through August 21, 2020, average sales volumes totaled 1,154 Boe/d for an overall average for the year ended December 31, 2020 of 1,925 Boe/d, an increase of 317% over 2019, due to the Company's successful horizontal drilling program in the Permian Basin.
•
Weighted average realized oil prices per Bbl decreased during the year ended December 31, 2020 to $37.96 ($40.15 during the period from August 22, 2020 through December 31, 2020 and $34.26 during the period from January 1, 2020 through August 21, 2020), compared with $53.96 for 2019. Weighted average NGL prices per Bbl were $14.06 during the year ended December 31, 2020 ($19.44 during the period from August 22, 2020 through December 31, 2020 and $9.31 per Bbl during the period from January 1, 2020 through August 21, 2020). This partially caused the decreased natural gas prices during 2020 as the Company recorded wet wellhead natural gas sales prior to 2020 which combines the revenues received from residue gas and NGL into one revenue component and sales volumes equal to wet wellhead volumes rather than processed residue natural gas and NGL at the tailgate of the processing plants. Weighted average gas prices per Mcf increased to $1.04 during the year ended December 31, 2020 ($1.45 during the period from August 22, 2020 through December 31, 2020 and $0.52 during the period from January 1, 2020 through August 21, 2020) compared with $1.92 during 2019.
•
Cash provided by operating activities totaled $5.4 million for the period from August 22, 2020 through December 31, 2020.
•
The Company raised $84.5 million of capital, net of offering costs, in the HighPeak business combination that closed on August 21, 2020. The Company closed a Revolving Credit Facility in December 2020 with an initial borrowing capacity of $20 million with nothing drawn as of December 31, 2020. This capital gave the Company flexibility to recommence its development drilling program whereby we have added one drilling rig that has drilled one salt-water disposal well and four producing wells during the Successor Period and as of December 31, 2020 was drilling on a two well pad in our development area. Shortly after Closing, we also added two completion crews to frac eight (8) of our twelve (12) uncompleted wells that were drilled but not fully completed when operations were shut down earlier this year due primarily to the COVID-19 pandemic and we also finished completing our four (4) additional uncompleted wells. We reduced to one completion crew prior to year-end that will focus on completing the wells both recently drilled and wells currently drilling.
First Quarter 2021 Outlook
The first quarter is likely to continue to offer a high degree of uncertainty and market disruption. The extent to which the Company's future results are affected by the COVID-19 pandemic will depend on various factors and consequences beyond the Company's control, such as the duration and scope of the pandemic, the length and severity of the worldwide economic recovery, additional actions by businesses, OPEC and other cooperating countries, and governments in response to the pandemic, economic downturn and decline in oil demand, the speed and effectiveness of responses to combat the virus, and the time necessary to balance oil supply and demand. For additional information on the risks posed by the COVID-19 pandemic, see “Part I, Item 1A. Risk Factors”.
Operations and Drilling Highlights
Average daily oil, NGL and gas sales volumes are as follows:
Successor
Predecessors
Combined
August 22,
2020
through
December
31 ,
2020
January 1,
2020 through
August 21,
2020
Year
Ended
December
31,
2020
Oil (Bbls)
3,017
1,007
1,732
NGL (Bbls)
134
86
103
Gas (Mcf)
849
373
545
Total (Boe)
3,292
1,154
1,925
The Company's liquids production was 95% of total production on a Boe basis for the year ended December 31, 2020.
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Costs incurred are as follows (in thousands):
Successor
Predecessors
Combined
August 22,
2020
through
December
31,
2020
January 1,
2020 through
August 21,
2020
Year
Ended
December
31,
2020
Unproved property acquisition costs
$
1,181
$
2,753
$
3,934
Proved acquisition costs
-
585
585
Total acquisitions
1,181
3,338
4,519
Development costs
11,687
933
12,620
Exploration costs
53,465
48,173
101,638
Total finding and development costs
66,333
52,444
118,777
Asset retirement obligations
(105
)
98
(7
)
Total costs incurred
$
66,228
$
52,542
$
118,770
Development and exploration/extension drilling activity is as follows:
Year Ended December 31, 2020
Development/
Service
Exploration/
Extension
Beginning wells in progress
-
13
Well spud
2
11
Successful wells
(2
)
(20
)
Ending wells in progress
-
4
The Company currently plans to operate one (1) drilling rig and an average of one (1) frac fleet in the Permian Basin during the first three months of 2021. However, the scope, duration and magnitude of the direct and indirect effects of the COVID-19 pandemic are continuing to evolve and in ways that are difficult or impossible to anticipate. Given the dynamic nature of this situation, the Company is maintaining flexibility in its capital plan and will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly.
During the year ended December 31, 2020, the Company successfully drilled twenty-one (21) horizontal wells in our northern acreage, thirteen of which are in the Wolfcamp A formation and eight of which are in the Lower Spraberry formations. In addition, the Company completed a horizontal salt-water disposal well near the center of our northern acreage production area which began accepting water for disposal in January 2021. Of the four (4) exploration/extension wells in progress as of December 31, 2020, two (2) of which were in the process of being drilled and two (2) of which were in the process of being completed, three (3) are in the Wolfcamp A formation and one (1) is in the Lower Spraberry formations.
Results of Operations
Sources of Revenues
The Company’s revenues are derived from the sale of oil and natural gas production and the sale of NGL that are extracted from natural gas during processing. Production revenues are derived entirely from the continental United States. For the years ended December 31, 2020 and 2019, revenues from our assets were derived approximately 98% and 97%, respectively, from oil sales and 2% and 3%, respectively, from natural gas and NGL sales.
The Company’s revenues are presented net of certain gathering, transportation and processing expenses incurred to deliver production of its assets’ oil, natural gas and NGL to the market. Cost levels of these expenses can vary based on the volume of oil, natural gas and NGL produced as well as the cost of commodity processing. Oil, natural gas and NGL prices are inherently volatile and are influenced by many factors outside the Company’s control. To reduce the impact of fluctuations in oil, natural gas and NGL prices on revenues, the Company may periodically enter into derivative contracts with respect to a portion of its estimated oil, natural gas and NGL production through various transactions that fix the future prices received.
Principal Components of Cost Structure
Costs associated with producing oil, natural gas and NGL are substantial. Some of these costs vary with commodity prices, some trend with the type and volume of production, and others are a function of the number of wells owned. The sections below summarize the primary operating costs typically incurred:
●
Lease Operating Expenses. Lease operating expenses (“LOE”) are the costs incurred in the operation of producing properties and workover costs. Expenses for utilities, direct labor, water injection and disposal, workover rigs and workover expenses, materials and supplies comprise the most significant portion of LOE. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to pumping equipment or surface facilities result in increased LOE in periods during which they are performed. Certain operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, power costs are incurred in connection with various production-related activities, such as pumping to recover oil and natural gas and separation and treatment of water produced in connection with oil and natural gas production.
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The Company monitors the operation of its assets to ensure that it is incurring LOE at an acceptable level. For example, it monitors LOE per Boe to determine if any wells or properties should be shut in, recompleted or sold. This unit rate also allows the Company to monitor these costs to identify trends and to benchmark against other producers. Although the Company strives to reduce its LOE, these expenses can increase or decrease on a per-unit basis as a result of various factors as it operates its assets or makes acquisitions and dispositions of properties. For example, the Company may increase field-level expenditures to optimize their operations, incurring higher expenses in one quarter relative to another, or they may acquire or dispose of properties that have different LOE per Boe. These initiatives would influence overall operating cost and could cause fluctuations when comparing LOE on a period-to-period basis.
●
Production and other taxes. Production and other taxes are paid on produced oil and natural gas based on rates established by federal, state or local taxing authorities. In general, production and other taxes paid correlate to changes in oil, natural gas and NGL revenues. Production taxes are based on the market value of production at the wellhead. The Company is also subject to ad valorem taxes in the counties where production is located. Ad valorem taxes are based on the fair market value of the mineral interests for producing wells.
●
Depletion – Oil and Gas Properties. Depletion is the systematic expensing of the capitalized costs incurred to acquire and develop oil and natural gas properties. The Company uses the successful efforts method of accounting for oil and gas properties. Accordingly, all costs associated with acquisition, successful exploration wells and development of oil and gas reserves, including directly related overhead costs and asset retirement costs are capitalized. However, the costs of abandoned properties, exploratory dry holes, geophysical costs and annual lease rentals are charged to expense as incurred. All capitalized costs of oil and gas properties are amortized on the unit-of-production method using estimates of proved reserves. Any remaining investments in unproved properties are not amortized until proved reserves associated with the projects can be determined or until impairment occurs.
●
General and Administrative Expenses. General and administrative expenses (“G&A”) are costs incurred for overhead, including payroll and benefits for corporate staff and costs of maintaining a headquarters, costs of managing production and development operations, IT expenses and audit and other fees for professional services, including legal compliance and acquisition-related expenses.
Factors Affecting the Comparability of the Predecessors Historical Financial Results
The comparability of the Predecessors’ results of operations among the periods presented, and for future periods, is impacted by the following factors:
●
The historical financial statements included herein are the financial statements of HighPeak I from January 1, 2019 to September 30, 2019, and the financial statements of HPK LP for the period from August 28, 2019 (Inception) through December 31, 2019 and for the period beginning January 1, 2020 and ending on August 21, 2020, as the Predecessors for financial reporting purposes, on a stand-alone basis, and as such, do not include financial information regarding the HighPeak II assets for all periods;
●
As a corporation, for U.S. federal income tax purposes, HighPeak Energy is subject to U.S. federal income taxes at a statutory rate of 21% of pretax earnings. This is a significant change from the Predecessors’ historical tax treatment because the Predecessors were each treated as a partnership for U.S. federal income tax purposes and, as such, the partners of the Predecessors reported their share of the Predecessor’s income or loss on their respective income tax returns;
●
Our assets will incur certain additional general and administrative expenses related to being owned by a publicly traded company, that were not previously incurred in HPK LP’s cost structure, including, but not limited to, Exchange Act reporting expenses; expenses associated with compliance with the Sarbanes-Oxley Act of 2002; expenses associated with being listed on a national securities exchange; incremental independent auditor fees; incremental legal fees; investor relations expenses; registrar and transfer agent fees; incremental director and officer liability insurance costs and non-management director compensation;
●
The Predecessors have completed acquisitions during the periods presented, including primarily the acquisition of undeveloped acreage for approximately $2.8 million, $6.3 million and $40.2 million during the period beginning January 1, 2020 and ending on August 21, 2020 and the years ended December 31, 2019 and 2018, respectively, and to a lesser extent producing properties and proved undeveloped reserves of approximately $585,000, $4.6 million and $881,000 during the period beginning January 1, 2020 and ending on August 21, 2020 and the years ended December 31, 2019 and 2018, respectively; and
●
During the period beginning January 1, 2020 and ending on August 21, 2020, HPK LP recognized a charge to expense of $76.5 million related to the termination of the Grenadier Acquisition (as defined in “Item 8. Financial Statements and Supplementary Data.”
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Year Ended December 31, 2020 Compared with Year Ended December 31, 2019
Oil and natural gas revenues.
Average daily sales volumes are as follows:
Year Ended December 31, 2020
Successor
Predecessors
August 22, 2020 through
December 31, 2020
January 1, 2020 through
August 21, 2020
Year Ended
December 31, 2019
Year to Year
% Change
Oil (Bbls)
3,017
1,007
399
334
%
NGL (Bbls)
134
86
-
100
%
Natural Gas (Mcf)
849
373
380
43
%
Total (Boe)
3,292
1,154
462
317
%
The increase in average daily Boe sales volumes for the year ended December 31, 2020, compared with 2019 was due to the Company's successful horizontal drilling program in the Wolfcamp A and Lower Spraberry formations.
The oil, NGL and natural gas prices that the Company reports are based on the market prices received for each commodity. The weighted average prices are as follows:
Year Ended December 31, 2020
Successor
Predecessors
August 22, 2020 through
December 31, 2020
January 1, 2020 through
August 21, 2020
Year Ended
December 31, 2019
Year to Year
% Change
Oil per Bbl
$
40.15
$
34.26
$
53.96
(28
)%
NGL per Bbl
$
19.44
$
9.31
$
n/a
100
%
Gas per Mcf
$
1.45
$
0.52
$
1.92
(39
)%
Total per Boe
$
37.74
$
30.44
$
48.13
(26
)%
The decrease in prices for oil and natural gas for the year ended December 31, 2020, compared with 2019 was due to a lower commodity price environment primarily as a result of the COVID-19 pandemic and over-supply.
Oil and natural gas production costs.
Oil and natural gas production costs in total and per Boe are as follows (in thousands, except percentages and per Boe amounts):
Year Ended December 31, 2020
Successor
Predecessors
August 22, 2020
through December
31, 2020
January 1, 2020
through August 21,
2020
Year Ended
December 31,
2019
Year to
Year %
Change
Lease operating expenses
$
2,653
$
4,870
$
3,372
123
%
Lease operating expenses per Boe
$
6.10
$
18.03
$
20.00
(66
)%
The increase in lease operating expenses can be attributed to the fact that by the end of 2020 we had nineteen (19) producing horizontal wells compared with only four (4) wells during at the end of 2019. Likewise, the decrease in lease operating expense per Boe for the year ended December 31, 2020, compared with 2019, was primarily attributable to the increased production volumes associated with the higher well count.
Production and ad valorem taxes.
Production and ad valorem taxes are as follows (in thousands, except percentages):
Year Ended December 31, 2020
Successor
Predecessors
August 22, 2020
through
December 31,
2020
January 1, 2020
through August
21, 2020
Year Ended
December
31, 2019
Year to
Year %
Change
Production and ad valorem taxes
$
886
$
566
$
449
223
%
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In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices.
Production and ad valorem taxes per Boe are as follows:
Year Ended December 31, 2020
Successor
Predecessors
August 22, 2020 through
December 31, 2020
January 1, 2020
through August 21,
2020
Year Ended
December 31,
2019
Year to
Year %
Change
Production taxes per Boe
$
1.78
$
1.42
$
1.65
2
%
Ad valorem taxes per Boe
$
0.26
$
0.68
$
1.01
(63
)%
Production taxes per Boe for the year ended December 31, 2020, compared with 2019, remained relatively unchanged. The decrease in ad valorem taxes per Boe for the year ended December 31, 2020, compared with 2019, was primarily due to a large number of wells that have come on production during 2020 that will have no ad valorem tax in the upcoming year as 2021 will be the first year that they will be assessed ad valorem taxes. In Texas, ad valorem taxes are based on a valuation of the wells on January 1 of a given year.
Depletion, depreciation and amortization expense.
Depletion, depreciation and amortization (“DD&A”) expense and DD&A expense per Boe are as follows (in thousands, except percentages and per Boe amounts):
Year Ended December 31, 2020
Successor
Predecessors
August 22, 2020 through
December 31, 2020
January 1, 2020
through August 21,
2020
Year Ended
December 31, 2019
Year to Year
% Change
DD&A expense
$
9,877
$
6,385
$
4,269
281
%
DD&A expense per Boe
$
22.73
$
23.64
$
25.32
(9
)%
The increase in DD&A was primarily due to the increased production associated with our successful horizontal drilling program. Also, the decrease in DD&A per Boe was primarily due to additions of proved reserves attributable to the Company's successful horizontal drilling program in the Wolfcamp A and Lower Spraberry formations.
General and administrative expense.
General and administrative expense and general and administrative expense per Boe as well as stock-based compensation expense are as follows (in thousands, except percentages and per Boe amounts):
Year Ended December 31, 2020
Successor
Predecessors
August 22, 2020
through December
31, 2020
January 1, 2020
through August
21, 2020
Year Ended
December 31,
2019
Year to
Year %
Change
General and administrative expense
$
2,775
$
4,840
$
8,682
(12
)%
General and administrative expense per Boe
$
6.39
$
17.92
$
51.49
(82
)%
Stock based compensation expense
$
15,776
$
-
$
-
100
%
The decrease in general and administrative expense for the year ended December 31, 2020, compared with 2019, is primarily due to the expenses related to the HighPeak business combination incurred during 2019 plus various cost reduction efforts implemented across the organization during 2020 in response to the COVID-19 pandemic and downturn in crude oil prices, partially offset by the increase in administrative costs incurred related to being a public company beginning in August 2020. The decrease in general and administrative expenses per Boe during the year ended December 31, 2020 can also be attributed to our successful horizontal drilling program in the Wolfcamp A and Lower Spraberry formations.
The increase in noncash stock-based compensation expense is due to stock options granted to officers and employees shortly after the Closing in connection with the HighPeak business combination. Approximately 75% of the stock options granted vested immediately. In addition, the Company issued 62,500 fully vested shares of common stock to the non-management directors in the fourth quarter of 2020.
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Income tax benefit.
Income tax benefit and effective income tax rates are as follows (in thousands, except percentages):
Year Ended December 31, 2020
Successor
Predecessors
August 22, 2020 through
December 31, 2020
January 1, 2020
through August 21,
2020
Year Ended
December 31,
2019
Year to Year
% Change
Income tax benefit
$
4,223
$
-
$
-
100
%
Effective income tax rate
20.4
%
0.0
%
0.0
%
100
%
The change in income tax benefit during the year ended December 31, 2020, compared with 2019, was due to the fact that the Predecessors were treated as partnerships for U.S. federal income tax purposes and, as such, the partners of the Predecessors reported their share of the Predecessor’s income or loss on their respective income tax returns. In contrast, HighPeak Energy is a corporation for U.S. federal income tax purposes and is subject to U.S. federal income taxes on any income or loss from the operation of the Company’s assets following the HighPeak business combination on August 21, 2020. The effective income tax rate differs from the statutory rate primarily due to permanent differences between GAAP income and taxable income. See “Item 8. Financial Statements and Supplementary Data -Note 12” for additional information.
Liquidity and Capital Resources
Liquidity . In response to the COVID-19 pandemic and commensurate decrease in oil and gas prices, the Company took steps during 2020 to reduce, defer or cancel certain planned capital expenditures, shut-in the majority of its production and reduce its overall cost structure commensurate with its expected level of activities. During July 2020, the Company began putting its wells back on production based on the recovery of oil and gas prices. Subsequent to the Closing of the HighPeak business combination, the Company began completing the twelve (12) wells that were drilled but not yet completed when operations were shut down early in 2020. The Company also began running one (1) drilling rig at that time. The Company drilled and completed a salt-water disposal well near the center of our current northern acreage operating area and constructed a water disposal infrastructure system to dispose the water that we anticipate producing with the development drilling planned in 2021 and beyond. Also, in late December 2020, the Company entered into a Revolving Credit Facility with an initial borrowing base of $40 million; however, the Company elected to reduce the aggregate elected commitments to $20 million. The Revolving Credit Facility was undrawn at year end. Associated with the Revolving Credit Facility, the Company is required to enter into commodity hedging instruments to protect against price fluctuations on a portion of its proved developed producing reserves commencing in the first quarter of 2021.
The Company's primary sources of short-term liquidity are (i) cash and cash equivalents, (ii) net cash provided by operating activities, (iii) borrowings from our Revolving Credit Facility, (iv) on an opportunistic basis, issuances of debt or equity securities and (v) other sources, such as sales of nonstrategic assets.
As of December 31, 2020, the Company had no outstanding borrowings and approximately $20 million available to borrow under its Revolving Credit Facility. The Company also had unrestricted cash on hand of $19.6 million as of December 31, 2020. In March 2021, the Company’s borrowing base and bank commitments under the Revolving Credit Facility were increased to $50 million, subject to finalization of customary documentation.
The Company's primary needs for cash are for (i) capital expenditures, (ii) acquisitions of oil and gas properties, (iii) payments of contractual obligations, and (iv) working capital obligations. Funding for these cash needs may be provided by any combination of the Company's sources of liquidity. Although the Company expects that its sources of funding will be adequate to fund its 2021 planned capital expenditures and provide adequate liquidity to fund other needs, no assurance can be given that such funding sources will be adequate to meet the Company's future needs.
2021 capital budget . In response to the uncertainty around the duration and overall impact to the Company caused by the COVID-19 pandemic, the Company has set its capital budget for 2021 at approximately $115 to $125 million for drilling, completion, facilities and equipping oil wells plus $20 to $25 million for field infrastructure buildout and other costs. HighPeak Energy expects to fund its forecasted capital expenditures with cash on its balance sheet, cash generated by operations and through borrowings under its Revolving Credit Facility. The Company's capital expenditures for the year ended December 31, 2020 were $118.8 million.
Capital resources . Cash flows from operating, investing and financing activities are summarized below (in thousands).
Year Ended December 31, 2020
Successor
Predecessors
August 22, 2020
through
December 31,
2020
January 1,
2020 through
August 21, 2020
Year Ended
December 31,
2019
Year to
Year
Change
Net cash provided by (used in) operating activities
$
5,413
$
(4,102
)
$
(772
)
$
2,080
Net cash used in investing activities
$
(71,939
)
$
(67,886
)
$
(51,434
)
$
(97,930
)
Net cash provided by financing activities
$
84,135
$
51,220
$
74,023
$
70,874
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Operating activities. The increase in net cash flow provided by operating activities for the year ended December 31, 2020, compared with 2019, was primarily due to an increase in cash flow from the statement of operations related mostly to increased revenues associated with increased production volumes as a result of our successful horizontal drilling program. Partially offsetting this increase was a decrease in accounts payable and accrued liabilities primarily related the relatively high amount of accrued expenses related to the HighPeak business combination, an increase in accounts receivable from the increased oil and gas revenues related to increased production volumes in December 2020 versus 2019 and federal income taxes receivable.
Investing activities. The increase in net cash used in investing activities for the year ended December 31, 2020, compared with 2019, was primarily due to increases in additions to oil and gas properties as the Company began a development drilling program with two rigs in late-2019 and continued through March 2020 at which time it paused its development drilling program. The Company recommenced its development drilling program with one rig in September 2020. The Company also funded an extension payment of $15.0 million related to an acquisition in 2020 that was terminated and funded notes receivable to Pure of $7.5 million related to the HighPeak business combination. Partially offsetting these increases in cash used in investing activities was a decrease in the amount of acquisitions of oil and gas properties during the year ended December 31, 2020 compared with 2019.
Financing activities. The Company's significant financing activities are as follows:
•
2020: The Company (i) received $84.5 million from the aforementioned HighPeak business combination, net of issuance fees, (ii) received $54.0 million in capital contributions from its partners prior to the Closing of the aforementioned HighPeak business combination, (iii) made distributions to its partners totaling $2.8 million prior to the Closing of the aforementioned HighPeak business combination, and (iv) spent $405,000 on debt issuance costs related to closing its Revolving Credit Facility in December 2020.
•
2019: The Company’s Predecessors received $74.0 million in capital contributions from its partners.
Contractual obligations. The Company's contractual obligations include leases (primarily related to contracted drilling rigs, equipment and office facilities), capital funding obligations and other liabilities. Other joint owners in the properties operated by the Company could incur portions of the costs represented by these commitments.
Critical Accounting Estimates
The Company prepares its consolidated and combined financial statements for inclusion in this Annual Report in accordance with GAAP. See Note 2 of Notes to Consolidated and Combined Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information. The following is a discussion of the Company's most critical accounting estimates, judgments and uncertainties that are inherent in the Company's application of GAAP.
Asset retirement obligations. The Company has significant obligations to remove tangible equipment and facilities and to restore the land at the end of oil and gas production operations. The Company's removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, 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 present value of the existing asset retirement obligations, a corresponding adjustment is generally made to the oil and gas property or other property and equipment balance. See Note 7 of Notes to Consolidated and Combined Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
Successful efforts method of accounting. The Company utilizes the successful efforts method of accounting for oil and gas producing activities as opposed to the alternate acceptable full cost method. In general, the Company believes that net assets and net income are more conservatively measured under the successful efforts method of accounting for oil and gas producing activities than under the full cost method, particularly during periods of active exploration. The critical difference between the successful efforts method of accounting and the full cost method is that under the successful efforts method, exploratory dry holes and geological and geophysical exploration costs are charged against earnings during the periods in which they occur; whereas, under the full cost method of accounting, such costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the earnings of future periods as a component of depletion expense.
Proved reserve estimates. Estimates of the Company's proved reserves included in this Annual Report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:
●
the quality and quantity of available data;
●
the interpretation of that data;
●
the accuracy of various mandated economic assumptions; and
●
the judgment of the persons preparing the estimate.
The Company's proved reserve information included in this Annual Report as of December 31, 2020 and 2019 was prepared by independent petroleum engineers. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, proved reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions, positively or negatively, to the estimate of proved reserves.
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It should not be assumed that the Standardized Measure included in this Annual Report as of December 31, 2020 is the current market value of the Company's estimated proved reserves. In accordance with SEC requirements, the Company based the 2020 Standardized Measure on a twelve month average of commodity prices on the first day of each month in 2020 and prevailing costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimate. See "Items 1 and 2. Business and Properties" and Unaudited Supplementary Information included in "Item 8. Financial Statements and Supplementary Data" for additional information.
The Company's estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which the Company records depletion expense will increase, reducing future net income. Such a decline may result from lower commodity prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of the Company's assessment of its proved properties for impairment.
Impairment of proved oil and gas properties. The Company reviews its proved properties to be held and used whenever management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Management assesses whether or not an impairment provision is necessary based upon estimated future recoverable proved and risk-adjusted probable and possible reserves, Management's price outlooks, production and capital costs expected to be incurred to recover the reserves, discount rates commensurate with the nature of the properties and net cash flows that may be generated by the properties. Proved oil and gas properties are reviewed for impairment at the level at which depletion of proved properties is calculated. See Note 2 of Notes to Consolidated and Combined Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
Impairment of unproved oil and gas properties. At December 31, 2020, the Company carried unproved property costs of $152.7 million. Management assesses unproved oil and gas properties for impairment on a project-by-project basis. Management's impairment assessments include evaluating the results of exploration activities, Management's price outlooks and planned future sales or expiration of all or a portion of such projects.
Suspended wells. The Company suspends the costs of exploratory wells that discover hydrocarbons pending a final determination of the commercial potential of the discovery. The ultimate disposition of these well costs is dependent on the results of future drilling activity and development decisions. If the Company decides not to pursue additional appraisal activities or development of these fields, the costs of these wells will be charged to exploration and abandonment expense.
The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met:
●
The well has found a sufficient quantity of reserves to justify its completion as a producing well; and
●
The Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and economics associated with making a determination of its commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies' production, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued constantly. Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the well has found sufficient quantities of proved reserves to sanction the project or is determined to be noncommercial and is impaired. See Note 5 of Notes to Consolidated and Combined Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
Deferred tax asset valuation allowances. The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that its deferred tax assets will be realized prior to their expiration. HighPeak Energy monitors Company-specific, oil and gas industry and worldwide economic factors and based on that information, along with other data, reassesses the likelihood that the Company's net operating loss carryforwards and other deferred tax attributes in each jurisdiction will be utilized prior to their expiration. There can be no assurance that facts and circumstances will not materially change and require the Company to establish deferred tax asset valuation allowances in certain jurisdictions in a future period.
Litigation and environmental contingencies. The Company makes judgments and estimates in recording liabilities for ongoing litigation and environmental remediation. Actual costs can vary from such estimates for a variety of reasons. The costs to settle litigation can vary from estimates based on differing interpretations of laws and opinions and assessments on the amount of damages. Similarly, environmental remediation liabilities are subject to change because of changes in laws and regulations, developing information relating to the extent and nature of site contamination and improvements in technology. A liability is recorded for these types of contingencies if the Company determines the loss to be both probable and reasonably estimable. See Note 9 of Notes to Consolidated and Combined Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
Valuation of stock-based compensation. The Company calculates the fair value of stock-based compensation using various valuation methods. The valuation methods require the use of estimates to derive the inputs necessary to determine fair value. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, and (ii) the closing stock price on the date of grant for the fair value of unrestricted stock awards. See Note 8 of Notes to Consolidated and Combined Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
Valuation of other assets and liabilities at fair value. The Company periodically measures and records certain assets and liabilities at fair value. The assets and liabilities the Company measures and records at fair value on a recurring basis include commodity derivative contracts and interest rate contracts. Other assets are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. The assets and liabilities the Company measures and records at fair value on a nonrecurring basis include inventories, proved and unproved oil and gas properties and other long-lived assets that are written down to fair value when they are determined to be impaired or held for sale. The Company also measures and discloses certain financial assets and liabilities at fair value, such as long-term debt. The valuation methods used by the Company to measure the fair values of these assets and liabilities may require considerable management judgment and estimates to derive the inputs necessary to determine fair value estimates, such as future prices, credit-adjusted risk-free rates and current volatility factors. See Note 4 of Notes to Consolidated and Combined Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
New Accounting Pronouncements
The effects of new accounting pronouncements are discussed in Note 2 of Notes to Consolidated and Combined Financial Statements included in “Item 8. Financial Statements and Supplementary Data – Note 2.”
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