Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2020, as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.
Executive Summary
We are an independent Denver-based exploration and production company focused on the acquisition, development, and extraction of oil and associated liquids-rich natural gas in the United States. Our oil and liquids-weighted assets and operations are concentrated in the rural portions of the Wattenberg Field in Colorado. Our development and extraction activities are primarily directed at the horizontal development of the Niobrara and Codell formations in the Denver-Julesburg (“DJ”) Basin. The majority of our revenues are generated through the sale of oil, natural gas, and natural gas liquids production.
The Company’s primary objective is to maximize shareholder returns by responsibly developing our oil and gas resources, paying down debt, and returning excess cash via dividends. We seek to balance production and company growth with maintaining a conservative balance sheet. Key aspects of our strategy include well-balanced asset mergers and acquisitions, multi-well pad development across our leasehold, enhanced completions through continuous design evaluation, utilization of scaled infrastructure, continuous safety improvement, strict adherence to health and safety regulations, and environmental stewardship.
Financial and Operating Results
Our financial and operational results include:
•Crude oil equivalent sales volumes increased 67% for the three months ended September 30, 2021 when compared to the same period in 2020 due to the HighPoint Merger;
•Lease operating expense increased in line with expectations by 29% per Boe for the three months ended September 30, 2021 when compared to the same period in 2020;
•General and administrative expense decreased by 13% per Boe for the three months ended September 30, 2021 when compared to the same period in 2020;
•Borrowings under our Credit Facility were reduced by $95.0 million to $60.0 million during the nine months ended September 30, 2021 from the $155.0 million borrowed at the closing of the HighPoint Merger to pay down the HighPoint credit facility, and were further reduced to zero outstanding as of the date of this filing;
•Total liquidity of $372.4 million at September 30, 2021, consisting of cash on hand plus funds available under our Credit Facility, after giving effect to undrawn letters of credit. Please refer to Liquidity and Capital Resources below for additional discussion;
•Cash dividends of $21.6 million, or $0.35 per share, declared and paid during the nine months ended September 30, 2021;
•Cash flows provided by operating activities for the nine months ended September 30, 2021 were $192.2 million compared to $111.4 million during the nine months ended September 30, 2020. Please refer to Liquidity and Capital Resources below for additional discussion; and
•Capital expenditures, inclusive of accruals, of $128.5 million during the nine months ended September 30, 2021.
Rocky Mountain Infrastructure
The Company's gathering, treating, and production facilities, maintained under its Rocky Mountain Infrastructure, LLC (“RMI”) subsidiary, provide many operational benefits to the Company and provide cost economies of a centralized system. The RMI facilities reduce gathering system pressures at the wellhead, thereby improving hydrocarbon recovery. Additionally, with eleven interconnects to four different natural gas processors, RMI helps ensure that the Company's production is not constrained by any single midstream service provider. Furthermore, in 2019, the Company installed a new oil gathering line to Riverside Terminal (on the Grand Mesa Pipeline), which resulted in a corresponding $1.25 to $1.50 per barrel reduction to our oil differentials for barrels transported on such gathering line. Additionally, the Company commenced construction of an additional oil interconnect in late June 2021, thus providing additional outlets to provide flow assurance and minimize differentials. The total value of reduced oil differentials during the nine months ended September 30, 2021 and 2020 was approximately $3.3 million and $4.7 million, respectively. Finally, the RMI system reduces facility site footprints, leading to more cost-efficient operations and reduced emissions and surface disturbance. The net book value of the Company's RMI assets was $196.7 million as of September 30, 2021.
Current Events and Outlook
The worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19, and various governmental actions taken to mitigate the impact of COVID-19, resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production further increased the excess supply of oil and natural gas throughout 2020. However, during 2021, expectations surrounding the demand for oil and natural gas stimulated a rise in oil and natural gas prices.
The COVID-19 outbreak and its development into a pandemic in March 2020 also required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, suppliers, and the communities in which we operate. Our operational employees are currently still able to work on site. However, we have taken various precautionary measures with respect to our operational employees such as requiring them to verify they have not experienced any symptoms consistent with COVID-19, or been in close contact with someone showing such symptoms, before reporting to the work site, quarantining any operational employees who have shown signs of COVID-19 (regardless of whether such employee has been confirmed to be infected), and imposing social distancing requirements on work sites, all in accordance with the guidelines released by the Centers for Disease Control and Prevention. We have not experienced any material operational disruptions (including disruptions from our suppliers and service providers) as a result of a COVID-19 outbreak.
The Company's stand-alone first quarter 2021 capital budget of $35 million to $40 million and combined second through fourth quarter 2021 capital budget (reflecting the closing of the HighPoint Merger on April 1, 2021) of $115 million to $130 million includes completing 45 gross (39.9 net) drilled, uncompleted wells, and picking up a drilling rig in the fourth quarter of 2021, with completions of those newly drilled wells to begin in 2022. Actual capital expenditures could vary significantly based on, among other things, market conditions, commodity prices, drilling and completion costs, and well results.
On April 1, 2021, we completed the previously announced acquisition of HighPoint. While we have already achieved significant synergies across several areas of the Company, there is an expected delay in realizing certain synergies and benefits due to the time and effort required to renegotiate and wait out certain contracts and integrate the formerly stand-alone companies. Consequently, the financial and operating results of the combined companies for the three and nine months ended September 30, 2021 reflect a slightly higher cost metric that we anticipate will decline through the end of 2021. Additionally, while the significant curtailment of the respective drilling and completion programs during 2020, in response to the drop in commodity prices, resulted in an overall decline in combined companies' sales volumes period over period, we expect sales volumes will recover considerably through 2021 completion activity as well as the return of a drilling rig in the fourth quarter of 2021.
The Company has successfully integrated the operations, production and accounting databases derived from the HighPoint Merger. The Company is confident it has the appropriate level of skills and personnel to successfully integrate the XOG and Crestone Peak mergers. The go-forward Company will incorporate the best practices and processes from each organization.
Results of Operations
The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
|
|
|
2021
|
|
2020
|
|
Change
|
|
Percent Change
|
|
Revenues (in thousands):
|
|
|
|
|
|
|
|
|
Crude oil sales(1)
|
$
|
131,103
|
|
|
$
|
46,808
|
|
|
$
|
84,295
|
|
|
180
|
%
|
|
Natural gas sales(2)
|
23,387
|
|
|
4,803
|
|
|
18,584
|
|
|
387
|
%
|
|
Natural gas liquids sales
|
33,838
|
|
|
5,866
|
|
|
27,972
|
|
|
477
|
%
|
|
Product revenue
|
$
|
188,328
|
|
|
$
|
57,477
|
|
|
$
|
130,851
|
|
|
228
|
%
|
|
|
|
|
|
|
|
|
|
|
Sales Volumes:
|
|
|
|
|
|
|
|
|
Crude oil (MBbls)
|
2,036.4
|
|
|
1,284.0
|
|
|
752.4
|
|
|
59
|
%
|
|
Natural gas (MMcf)
|
6,647.5
|
|
|
3,629.3
|
|
|
3,018.2
|
|
|
83
|
%
|
|
Natural gas liquids (MBbls)
|
880.2
|
|
|
524.9
|
|
|
355.3
|
|
|
68
|
%
|
|
Crude oil equivalent (MBoe)(3)
|
4,024.5
|
|
|
2,413.8
|
|
|
1,610.7
|
|
|
67
|
%
|
|
|
|
|
|
|
|
|
|
|
Average Sales Prices (before derivatives):
|
|
|
|
|
|
|
|
|
Crude oil (per Bbl)
|
$
|
64.38
|
|
|
$
|
36.45
|
|
|
$
|
27.93
|
|
|
77
|
%
|
|
Natural gas (per Mcf)
|
$
|
3.52
|
|
|
$
|
1.32
|
|
|
$
|
2.20
|
|
|
167
|
%
|
|
Natural gas liquids (per Bbl)
|
$
|
38.44
|
|
|
$
|
11.18
|
|
|
$
|
27.26
|
|
|
244
|
%
|
|
Crude oil equivalent (per Boe)(3)
|
$
|
46.80
|
|
|
$
|
23.81
|
|
|
$
|
22.99
|
|
|
97
|
%
|
|
|
|
|
|
|
|
|
|
|
Average Sales Prices (after derivatives)(4):
|
|
|
|
|
|
|
|
|
Crude oil (per Bbl)
|
$
|
54.64
|
|
|
$
|
43.59
|
|
|
$
|
11.05
|
|
|
25
|
%
|
|
Natural gas (per Mcf)
|
$
|
2.51
|
|
|
$
|
1.18
|
|
|
$
|
1.33
|
|
|
113
|
%
|
|
Natural gas liquids (per Bbl)
|
$
|
38.44
|
|
|
$
|
11.18
|
|
|
$
|
27.26
|
|
|
244
|
%
|
|
Crude oil equivalent (per Boe)(3)
|
$
|
40.20
|
|
|
$
|
27.39
|
|
|
$
|
12.81
|
|
|
47
|
%
|
_____________________________
(1)Crude oil sales excludes $0.2 million and $0.4 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the three months ended September 30, 2021 and 2020, respectively.
(2)Natural gas sales excludes $1.4 million and $1.0 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the three months ended September 30, 2021 and 2020, respectively.
(3)Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
(4)Derivatives economically hedge the price we receive for crude oil and natural gas. For the three months ended September 30, 2021, the derivative cash settlement loss for oil and natural gas contracts was $19.8 million and $6.7 million, respectively. For the three months ended September 30, 2020, the derivative cash settlement gain for oil contracts was $9.2 million, and the derivative cash settlement loss for natural gas contracts was $0.5 million. Please refer to Note 10 - Derivatives of Part I, Item 1 of this report for additional disclosures.
Product revenues increased by 228% to $188.3 million for the three months ended September 30, 2021 compared to $57.5 million for the three months ended September 30, 2020. The drivers of the increase in revenue are the 97%, or $22.99 per Boe, increase in oil equivalent pricing and the 67% increase in sales volumes. The increase in sales volumes is primarily due to the HighPoint Merger that closed on April 1, 2021. Additionally, we turned 30 gross wells to sales during the twelve-month period ending September 30, 2021.
The following table summarizes our operating expenses for the periods indicated:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
|
|
|
2021
|
|
2020
|
|
Change
|
|
Percent Change
|
|
Expenses (in thousands):
|
|
|
|
|
|
|
|
|
Lease operating expense
|
$
|
11,560
|
|
|
$
|
5,393
|
|
|
$
|
6,167
|
|
|
114
|
%
|
|
Midstream operating expense
|
3,163
|
|
|
3,970
|
|
|
(807)
|
|
|
(20)
|
%
|
|
Gathering, transportation, and processing
|
14,105
|
|
|
4,778
|
|
|
9,327
|
|
|
195
|
%
|
|
Severance and ad valorem taxes
|
9,205
|
|
|
(7,063)
|
|
|
16,268
|
|
|
230
|
%
|
|
Exploration
|
1,513
|
|
|
66
|
|
|
1,447
|
|
|
2,192
|
%
|
|
Depreciation, depletion, and amortization
|
35,604
|
|
|
23,439
|
|
|
12,165
|
|
|
52
|
%
|
|
Abandonment and impairment of unproved properties
|
—
|
|
|
223
|
|
|
(223)
|
|
|
(100)
|
%
|
|
Unused commitments
|
3,364
|
|
|
—
|
|
|
3,364
|
|
|
100
|
%
|
|
Bad debt expense
|
279
|
|
|
102
|
|
|
177
|
|
|
174
|
%
|
|
Merger transaction costs
|
5,580
|
|
|
888
|
|
|
4,692
|
|
|
528
|
%
|
|
General and administrative expense
|
11,724
|
|
|
8,031
|
|
|
3,693
|
|
|
46
|
%
|
|
Operating Expenses
|
$
|
96,097
|
|
|
$
|
39,827
|
|
|
$
|
56,270
|
|
|
141
|
%
|
|
|
|
|
|
|
|
|
|
|
Selected Costs ($ per Boe):
|
|
|
|
|
|
|
|
|
Lease operating expense
|
$
|
2.87
|
|
|
$
|
2.23
|
|
|
$
|
0.64
|
|
|
29
|
%
|
|
Midstream operating expense
|
0.79
|
|
|
1.64
|
|
|
(0.85)
|
|
|
(52)
|
%
|
|
Gathering, transportation, and processing
|
3.50
|
|
|
1.98
|
|
|
1.52
|
|
|
77
|
%
|
|
Severance and ad valorem taxes
|
2.29
|
|
|
(2.93)
|
|
|
5.22
|
|
|
(178)
|
%
|
|
Exploration
|
0.38
|
|
|
0.03
|
|
|
0.35
|
|
|
1,167
|
%
|
|
Depreciation, depletion, and amortization
|
8.85
|
|
|
9.71
|
|
|
(0.86)
|
|
|
(9)
|
%
|
|
Abandonment and impairment of unproved properties
|
—
|
|
|
0.09
|
|
|
(0.09)
|
|
|
(100)
|
%
|
|
Unused commitments
|
0.84
|
|
|
—
|
|
|
0.84
|
|
|
100
|
%
|
|
Bad debt expense
|
0.07
|
|
|
0.04
|
|
|
0.03
|
|
|
75
|
%
|
|
Merger transaction costs
|
1.39
|
|
|
0.37
|
|
|
1.02
|
|
|
276
|
%
|
|
General and administrative expense
|
2.91
|
|
|
3.33
|
|
|
(0.42)
|
|
|
(13)
|
%
|
|
Operating Expenses
|
$
|
23.89
|
|
|
$
|
16.49
|
|
|
$
|
7.40
|
|
|
45
|
%
|
Lease operating expense. Our lease operating expense increased by $6.2 million, or 114%, to $11.6 million for the three months ended September 30, 2021 from $5.4 million for the three months ended September 30, 2020, and 29% on an equivalent basis per Boe. Lease operating expense on an aggregate basis increased as a result of the HighPoint Merger. Additionally, our overall lease operating expense during the three months ended September 30, 2020 was at an unprecedented low due to the Company's concerted effort to reduce costs in response to the decline in commodity pricing during the 2020 period. The increase in lease operating expense outpaced the increase in sales volumes causing the per Boe to increase, which is within expectations and guidance on a per Boe basis.
Midstream operating expense. Our midstream operating expense decreased to $3.2 million for the three months ended September 30, 2021 compared to $4.0 million for the three months ended September 30, 2020, and decreased 52% on a per Boe basis during the comparable periods. The aggregate decrease is due to reduced compression rentals resulting from the acquisition of a significant number of owned compressors through the HighPoint Merger. Additionally, while certain midstream operating expenses correlate to sales volumes, the majority of the costs, such as compression, are fixed and thereby result in a decrease in midstream operating expense per Boe period over period.
Gathering, transportation, and processing. Gathering, transportation, and processing expense increased by $9.3 million to $14.1 million for the three months ended September 30, 2021, from $4.8 million for the three months ended September 30, 2020, and increased 77% on a per Boe basis during the comparable periods. Natural gas and NGLs sales volumes have a direct correlation to gathering, transportation, and processing expense, and natural gas and NGLs sales volumes increased 76% during the comparable periods. Additionally, our value-based percentage of proceeds sales contract is now our largest sales contract post the HighPoint Merger, which tracks solely with natural gas and NGLs pricing. Natural gas and NGLs pricing increased at a faster pace than the natural gas and NGLs sales volumes associated with said pricing causing the per Boe to increase.
Severance and ad valorem taxes. Our severance and ad valorem taxes increased to $9.2 million for the three months ended September 30, 2021, from a credit of $7.1 million for the three months ended September 30, 2020. Severance and ad valorem taxes primarily correlate to revenues, and revenues increased by 228% during the three months ended September 30, 2021 compared to the three months ended September 30, 2020. Offsetting this increase is a decrease in the Company's overall severance and ad valorem tax rates as a result of the HighPoint Merger, due to HighPoint having a substantial amount of wells in lower taxing districts. Finally, we refined our tax estimate based on then mill levies, taxing districts, and company results based on commodity prices during the third quarter 2020, which resulted in a one-time adjustment of $12.6 million. Excluding this adjustment, our severance and ad valorem taxes were $5.5 million for the three months ended September 30, 2020.
Exploration. Our exploration expense increased to $1.5 million for the three months ended September 30, 2021, from $0.1 million for the three months ended September 30, 2020 primarily due to the initiation of geologic science studies on certain locations to determine drilling viability.
Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense increased 52% to $35.6 million for the three months ended September 30, 2021, from $23.4 million for the three months ended September 30, 2020, and decreased 9% on a per Boe basis during the comparable periods. The increase in depreciation, depletion, and amortization expense during the comparable periods is due to a $655.5 million increase in the depletable property base primarily due to the HighPoint Merger. The decrease on a per Boe basis is due to a decrease in the depletion rate.
Unused commitments. During the three months ended September 30, 2021 and 2020, we incurred $3.4 million and zero, respectively, in unused commitments. As part of the HighPoint Merger, we assumed two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from properties HighPoint had previously sold. Both firm transportation contracts required the pipeline to provide transportation capacity and required us to pay transportation charges regardless of the amount of pipeline capacity utilized. The agreements expired July 31, 2021.
Merger transaction costs. Our merger transaction costs increased by $4.7 million for the three months ended September 30, 2021 compared to the three months ended September 30, 2020 due to the closed HighPoint Merger and the anticipated XOG and Crestone Peak mergers.
General and administrative. Our general and administrative expense for the three months ended September 30, 2021 increased to $11.7 million compared to $8.0 million for three months ended September 30, 2020, and decreased 13% on a per Boe basis. The primary drivers of the aggregate increase relate to an increase in salaries, benefits, and stock compensation expense due to the HighPoint Merger. Additionally, certain one-time nonrecurring fees were incurred as it relates to the HighPoint Merger as further discussed in Note 3 - Acquisitions & Divestitures of Part I, Item 1 of this report. General and administrative expense per Boe decreased due to sales volumes being 67% higher during the three months ended September 30, 2021 as compared to the same period in 2020.
Derivative gain (loss). Our derivative losses for the three months ended September 30, 2021 and 2020 of $36.2 million and $10.7 million, respectively, were due to settlements and fair market value adjustments caused by market prices being higher than our contracted hedge prices. Please refer to Note 10 - Derivatives of Part I, Item 1 of this report for additional discussion.
Interest expense. Our interest expense for the three months ended September 30, 2021 and 2020 was $3.0 million and $0.4 million, respectively. Average debt outstanding for the three months ended September 30, 2021 and 2020 was $86.8 million and $54.1 million, respectively. The components of interest expense for the periods presented are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
2021
|
|
2020
|
|
Senior Notes
|
$
|
1,875
|
|
|
$
|
—
|
|
|
Credit Facility
|
777
|
|
|
334
|
|
|
Commitment and letter of credit fees under the Credit Facility
|
577
|
|
|
264
|
|
|
Amortization of deferred financing costs
|
437
|
|
|
92
|
|
|
Capitalized interest
|
(641)
|
|
|
(334)
|
|
|
Total interest expense, net
|
$
|
3,025
|
|
|
$
|
356
|
|
The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
|
|
|
2021
|
|
2020
|
|
Change
|
|
Percent Change
|
|
Revenues (in thousands):
|
|
|
|
|
|
|
|
|
Crude oil sales(1)
|
$
|
296,826
|
|
|
$
|
125,956
|
|
|
$
|
170,870
|
|
|
136
|
%
|
|
Natural gas sales(2)
|
50,451
|
|
|
13,696
|
|
|
36,755
|
|
|
268
|
%
|
|
Natural gas liquids sales
|
69,578
|
|
|
11,652
|
|
|
57,926
|
|
|
497
|
%
|
|
Product revenue
|
$
|
416,855
|
|
|
$
|
151,304
|
|
|
$
|
265,551
|
|
|
176
|
%
|
|
|
|
|
|
|
|
|
|
|
Sales Volumes:
|
|
|
|
|
|
|
|
|
Crude oil (MBbls)
|
4,884.3
|
|
|
3,787.6
|
|
|
1,096.7
|
|
|
29
|
%
|
|
Natural gas (MMcf)
|
16,267.0
|
|
|
10,490.6
|
|
|
5,776.4
|
|
|
55
|
%
|
|
Natural gas liquids (MBbls)
|
2,156.9
|
|
|
1,399.9
|
|
|
757.0
|
|
|
54
|
%
|
|
Crude oil equivalent (MBoe)(3)
|
9,752.4
|
|
|
6,935.9
|
|
|
2,816.5
|
|
|
41
|
%
|
|
|
|
|
|
|
|
|
|
|
Average Sales Prices (before derivatives):
|
|
|
|
|
|
|
|
|
Crude oil (per Bbl)
|
$
|
60.77
|
|
|
$
|
33.25
|
|
|
$
|
27.52
|
|
|
83
|
%
|
|
Natural gas (per Mcf)
|
$
|
3.10
|
|
|
$
|
1.31
|
|
|
$
|
1.79
|
|
|
137
|
%
|
|
Natural gas liquids (per Bbl)
|
$
|
32.26
|
|
|
$
|
8.32
|
|
|
$
|
23.94
|
|
|
288
|
%
|
|
Crude oil equivalent (per Boe)(3)
|
$
|
42.74
|
|
|
$
|
21.81
|
|
|
$
|
20.93
|
|
|
96
|
%
|
|
|
|
|
|
|
|
|
|
|
Average Sales Prices (after derivatives)(4):
|
|
|
|
|
|
|
|
|
Crude oil (per Bbl)
|
$
|
52.28
|
|
|
$
|
44.37
|
|
|
$
|
7.91
|
|
|
18
|
%
|
|
Natural gas (per Mcf)
|
$
|
2.54
|
|
|
$
|
1.34
|
|
|
$
|
1.20
|
|
|
90
|
%
|
|
Natural gas liquids (per Bbl)
|
$
|
32.26
|
|
|
$
|
8.32
|
|
|
$
|
23.94
|
|
|
288
|
%
|
|
Crude oil equivalent (per Boe)(3)
|
$
|
37.56
|
|
|
$
|
27.94
|
|
|
$
|
9.62
|
|
|
34
|
%
|
_____________________________
(1)Crude oil sales excludes $0.7 million and $1.4 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the nine months ended September 30, 2021 and 2020, respectively.
(2)Natural gas sales excludes $2.6 million and $2.8 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the nine months ended September 30, 2021 and 2020, respectively.
(3)Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
(4)Derivatives economically hedge the price we receive for crude oil and natural gas. For the nine months ended September 30, 2021, the derivative cash settlement loss for oil and natural gas contracts was $41.5 million and $9.1 million, respectively. For the nine months ended September 30, 2020, the derivative cash settlement gain for oil and natural gas contracts was $42.1 million and $0.4 million, respectively. Please refer to Note 10 - Derivatives of Part I, Item 1 of this report for additional disclosures.
Product revenues increased by 176% to $416.9 million for the nine months ended September 30, 2021 compared to $151.3 million for the nine months ended September 30, 2020. The primary drivers of the increase in revenue are the 96%, or $20.93 per Boe, increase in oil equivalent pricing and the 41% increase in sales volumes. The increase in sales volumes is due to turning 30 gross wells to sales during the twelve-month period ending September 30, 2021 as well as the HighPoint Merger that closed on April 1, 2021.
The following table summarizes our operating expenses for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
|
|
|
2021
|
|
2020
|
|
Change
|
|
Percent Change
|
|
Expenses (in thousands):
|
|
|
|
|
|
|
|
|
Lease operating expense
|
$
|
28,649
|
|
|
$
|
16,887
|
|
|
$
|
11,762
|
|
|
70
|
%
|
|
Midstream operating expense
|
11,314
|
|
|
11,338
|
|
|
(24)
|
|
|
—
|
%
|
|
Gathering, transportation, and processing
|
32,793
|
|
|
11,970
|
|
|
20,823
|
|
|
174
|
%
|
|
Severance and ad valorem taxes
|
23,622
|
|
|
1,588
|
|
|
22,034
|
|
|
1,388
|
%
|
|
Exploration
|
5,156
|
|
|
551
|
|
|
4,605
|
|
|
836
|
%
|
|
Depreciation, depletion, and amortization
|
89,433
|
|
|
67,306
|
|
|
22,127
|
|
|
33
|
%
|
|
Abandonment and impairment of unproved properties
|
2,215
|
|
|
30,589
|
|
|
(28,374)
|
|
|
(93)
|
%
|
|
Unused commitments
|
7,692
|
|
|
—
|
|
|
7,692
|
|
|
100
|
%
|
|
Bad debt expense
|
279
|
|
|
678
|
|
|
(399)
|
|
|
(59)
|
%
|
|
Merger transaction costs
|
27,121
|
|
|
909
|
|
|
26,212
|
|
|
2,884
|
%
|
|
General and administrative expense
|
33,119
|
|
|
25,845
|
|
|
7,274
|
|
|
28
|
%
|
|
Operating Expenses
|
$
|
261,393
|
|
|
$
|
167,661
|
|
|
$
|
93,732
|
|
|
56
|
%
|
|
|
|
|
|
|
|
|
|
|
Selected Costs ($ per Boe):
|
|
|
|
|
|
|
|
|
Lease operating expense
|
$
|
2.94
|
|
|
$
|
2.43
|
|
|
$
|
0.51
|
|
|
21
|
%
|
|
Midstream operating expense
|
1.16
|
|
|
1.63
|
|
|
(0.47)
|
|
|
(29)
|
%
|
|
Gathering, transportation, and processing
|
3.36
|
|
|
1.73
|
|
|
1.63
|
|
|
94
|
%
|
|
Severance and ad valorem taxes
|
2.42
|
|
|
0.23
|
|
|
2.19
|
|
|
952
|
%
|
|
Exploration
|
0.53
|
|
|
0.08
|
|
|
0.45
|
|
|
563
|
%
|
|
Depreciation, depletion, and amortization
|
9.17
|
|
|
9.70
|
|
|
(0.53)
|
|
|
(5)
|
%
|
|
Abandonment and impairment of unproved properties
|
0.23
|
|
|
4.41
|
|
|
(4.18)
|
|
|
(95)
|
%
|
|
Unused commitments
|
0.79
|
|
|
—
|
|
|
0.79
|
|
|
100
|
%
|
|
Bad debt expense
|
0.03
|
|
|
0.10
|
|
|
(0.07)
|
|
|
(70)
|
%
|
|
Merger transaction costs
|
2.78
|
|
|
0.13
|
|
|
2.65
|
|
|
2,038
|
%
|
|
General and administrative expense
|
3.40
|
|
|
3.73
|
|
|
(0.33)
|
|
|
(9)
|
%
|
|
Operating Expenses
|
$
|
26.81
|
|
|
$
|
24.17
|
|
|
$
|
2.64
|
|
|
11
|
%
|
Lease operating expense. Our lease operating expense increased 70% to $28.6 million for the nine months ended September 30, 2021 from $16.9 million for the nine months ended September 30, 2020 and increased 21% on an equivalent basis per Boe. Lease operating expense on an aggregate basis increased as a result of the HighPoint Merger. Additionally, our overall lease operating expense during the nine months ended September 30, 2020 was at an unprecedented low due to the Company's concerted effort to reduce costs in response to the decline in commodity pricing during the 2020 period. The increase in lease operating expense outpaced the increase in sales volumes causing the per Boe to increase, which is within expectations and guidance on a per Boe basis.
Midstream operating expense. Our midstream operating expense remained relatively consistent at $11.3 million for the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020, and decreased 29% on a per Boe basis during the comparable periods. While certain midstream operating expenses correlate to sales volumes, the majority of the costs, such as compression, are fixed and result in a decrease in midstream operating expense per Boe period over period.
Gathering, transportation, and processing. Gathering, transportation, and processing expense increased by $20.8 million, or 174%, to $32.8 million for the nine months ended September 30, 2021, from $12.0 million for the nine months ended September 30, 2020. Generally, natural gas and NGLs sales volumes have a direct correlation to gathering, transportation, and processing expense. Natural gas and NGLs sales volumes increased 55% during the comparable periods. Additionally, our value-based percentage of proceeds sales contract is now our largest sales contract post the HighPoint Merger, which tracks solely with natural gas and NGLs pricing. Natural gas and NGLs pricing increased at a faster pace than the natural gas and NGLs sales volumes associated with said pricing causing the per Boe to increase.
Severance and ad valorem taxes. Our severance and ad valorem taxes increased to $23.6 million for the nine months ended September 30, 2021, from $1.6 million for the nine months ended September 30, 2020. Severance and ad valorem taxes primarily correlate to revenues, and revenues increased by 176% during the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020. Offsetting this increase is a decrease in the Company's overall severance and ad valorem tax rates as a result of the HighPoint Merger, due to HighPoint having a substantial amount of wells in lower taxing districts. Finally, we refined our tax estimate based on current mill levies, taxing districts, and company results based on commodity prices during the third quarter 2020, which resulted in a one-time adjustment of $12.6 million. Excluding this adjustment, our severance and ad valorem taxes were $14.2 million for the nine months ended September 30, 2020.
Exploration. Our exploration expense increased to $5.2 million for the nine months ended September 30, 2021, from $0.6 million for the nine months ended September 30, 2020 primarily due to a one-time purchase of seismic and core data as well as the initiation of geologic science studies on certain locations to determine drilling viability.
Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense increased 33% to $89.4 million for the nine months ended September 30, 2021, from $67.3 million for the nine months ended September 30, 2020, and decreased 5% on a per Boe basis during the comparable periods. The increase in depreciation, depletion, and amortization expense during the comparable periods is due to a $655.5 million increase in the depletable property base primarily due to the HighPoint Merger. The decrease on a per Boe basis is due to a decrease in the depletion rate.
Abandonment and impairment of unproved properties. During the nine months ended September 30, 2021 and 2020, we incurred $2.2 million and $30.6 million, respectively, in abandonment and impairment of unproved properties primarily due to the reassessment of estimated probable and possible reserve locations based primarily upon economic viability and the expiration of non-core leases.
Unused commitments. During the nine months ended September 30, 2021 and 2020, we incurred $7.7 million and zero, respectively, in unused commitments. As part of the HighPoint Merger, we assumed two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from properties HighPoint had previously sold. Both firm transportation contracts required the pipeline to provide transportation capacity and required us to pay transportation charges regardless of the amount of pipeline capacity utilized. The agreements expired July 31, 2021.
Merger transaction costs. Our merger transaction costs increased by $26.2 million for the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020 largely due to the closed HighPoint Merger and, to a lesser degree, the anticipated XOG and Crestone Peak mergers.
General and administrative. Our general and administrative expense for the nine months ended September 30, 2021 increased to $33.1 million, from $25.8 million for the nine months ended September 30, 2020, and decreased 9% on a per Boe basis. The primary drivers of the increase relate to an increase in salaries, benefits, and stock compensation expense due to the HighPoint Merger. Additionally, certain one-time nonrecurring fees were incurred as it relates to the HighPoint Merger as further discussed in Note 3 - Acquisitions & Divestitures of Part I, Item 1 of this report. General and administrative expense per Boe decreased due to sales volumes being 41% higher in the later period as a result of the HighPoint Merger.
Derivative gain (loss). Our derivative loss for the nine months ended September 30, 2021 was $133.6 million due to settlements and fair market value adjustments caused by market prices being higher than our contracted hedge prices. Our derivative gain of $64.6 million for the nine months ended September 30, 2020 was due to settlements and fair market value adjustments caused by market prices being lower than our contracted hedge prices. Please refer to Note 10 - Derivatives of Part I, Item 1 of this report for additional discussion.
Interest expense. Our interest expense for the nine months ended September 30, 2021 and 2020 was $6.7 million and $1.6 million, respectively. Average debt outstanding for the nine months ended September 30, 2021 and 2020 was $70.3 million and $67.5 million, respectively. The components of interest expense for the periods presented are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
2021
|
|
2020
|
|
Senior Notes
|
$
|
3,750
|
|
|
$
|
—
|
|
|
Credit Facility
|
1,937
|
|
|
1,701
|
|
|
Commitment and letter of credit fees under the Credit Facility
|
1,232
|
|
|
785
|
|
|
Amortization of deferred financing costs
|
963
|
|
|
772
|
|
|
Capitalized interest
|
(1,197)
|
|
|
(1,701)
|
|
|
Total interest expense, net
|
$
|
6,685
|
|
|
$
|
1,557
|
|
Liquidity and Capital Resources
The Company's anticipated sources of liquidity include cash from operating activities, borrowings under the Credit Facility, proceeds from sales of assets, and potential proceeds from capital and/or debt markets. Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity, regulatory constraints, and other supply chain dynamics, among other factors. To mitigate some of the pricing risk, as of September 30, 2021, we have hedged approximately 18,500 Bbls per day for the remainder of 2021, representing almost 84% of our oil sales volume during the three months ended September 30, 2021.
As of September 30, 2021, our liquidity was $372.4 million, consisting of $40.4 million of cash on hand and $332.0 million of available borrowing capacity on the Credit Facility, after giving effect to an aggregate of $8.0 million of undrawn letters of credit.
Our weighted-average interest rate on borrowings from the Credit Facility was 3.5% for the three months ended September 30, 2021. As of September 30, 2021 and the date of this filing, we had $60.0 million and zero, respectively, outstanding on our Credit Facility.
On April 1, 2021, in conjunction with the HighPoint Merger, the Company, together with certain of its subsidiaries, entered into the Second Amendment to the Credit Facility. Please refer to Note 3 - Acquisitions and Divestitures under Part I, Item 1 for additional information.
The following table summarizes our cash flows and other financial measures for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
2021
|
|
2020
|
|
Net cash provided by operating activities
|
$
|
192,243
|
|
|
$
|
111,444
|
|
|
Net cash used in investing activities
|
(54,868)
|
|
|
(57,509)
|
|
|
Net cash used in financing activities
|
(121,708)
|
|
|
(61,158)
|
|
|
Cash, cash equivalents, and restricted cash
|
40,512
|
|
|
3,872
|
|
|
Acquisition of oil and gas properties
|
(620)
|
|
|
(853)
|
|
|
Exploration and development of oil and gas properties
|
(104,207)
|
|
|
(56,216)
|
|
Cash flows provided by operating activities
Our cash flows for the nine months ended September 30, 2021 and 2020 include cash receipts and disbursements attributable to our normal operating cycle. See Results of Operations above for more information on the factors driving these changes.
Cash flows used in investing activities
Expenditures for development of oil and natural gas properties are the primary use of our capital resources. The Company spent $104.2 million and $56.2 million on the exploration and development of oil and gas properties during the nine months ended September 30, 2021 and 2020, respectively. Partially offsetting these cash outflows for the nine months ended September 30, 2021 is the $49.8 million of cash acquired through the HighPoint Merger.
Cash flows provided by financing activities
Net cash used in financing activities for the nine months ended September 30, 2021 and 2020 was $121.7 million and $61.2 million, respectively. The change was primarily due to a $34.0 million increase in net payments on our Credit Facility between the comparable periods as well as the dividends paid in June and September 2021 totaling $21.6 million.
Non-GAAP Financial Measures
Adjusted EBITDAX represents earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash and non-recurring charges. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we present because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, and acquisitions and to service debt. We are also subject to financial covenants under our Credit Facility based on adjusted EBITDAX ratios as further described Note 5 - Long-Term Debt in Part I, Item I of this document. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all, items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies.
The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted EBITDAX (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
Net income
|
|
$
|
40,659
|
|
|
$
|
3,251
|
|
|
$
|
15,221
|
|
|
$
|
42,900
|
|
|
Exploration
|
|
1,513
|
|
|
66
|
|
|
5,156
|
|
|
551
|
|
|
Depreciation, depletion, and amortization
|
|
35,604
|
|
|
23,439
|
|
|
89,433
|
|
|
67,306
|
|
|
Abandonment and impairment of unproved properties
|
|
—
|
|
|
223
|
|
|
2,215
|
|
|
30,589
|
|
|
Unused commitments
|
|
3,364
|
|
|
—
|
|
|
7,692
|
|
|
—
|
|
|
Stock-based compensation (1)
|
|
2,289
|
|
|
1,723
|
|
|
6,096
|
|
|
4,436
|
|
|
Non-recurring general and administrative expense (1)
|
|
150
|
|
|
140
|
|
|
1,444
|
|
|
1,337
|
|
|
Merger transaction costs
|
|
5,580
|
|
|
888
|
|
|
27,121
|
|
|
909
|
|
|
(Gain) loss on property transactions, net
|
|
(951)
|
|
|
—
|
|
|
(951)
|
|
|
1,398
|
|
|
Interest expense, net
|
|
3,025
|
|
|
356
|
|
|
6,685
|
|
|
1,557
|
|
|
Severance and ad valorem taxes adjustment (2)
|
|
—
|
|
|
(12,586)
|
|
|
—
|
|
|
(12,586)
|
|
|
Derivative (gain) loss
|
|
36,224
|
|
|
10,670
|
|
|
133,613
|
|
|
(64,603)
|
|
|
Derivative cash settlements gain (loss)
|
|
(26,546)
|
|
|
8,627
|
|
|
(50,536)
|
|
|
42,494
|
|
|
Income tax expense
|
|
15,596
|
|
|
4,689
|
|
|
5,160
|
|
|
4,689
|
|
|
Adjusted EBITDAX
|
|
$
|
116,507
|
|
|
$
|
41,486
|
|
|
$
|
248,349
|
|
|
$
|
120,977
|
|
|
_____________________________
|
|
|
|
|
|
|
|
|
|
(1) Included as a portion of general and administrative expense in the accompanying statements of operations.
|
|
(2) Included as a portion of severance and ad valorem taxes in the accompanying statements of operations.
|
New Accounting Pronouncements
Please refer to Note 2 — Basis of Presentation under Part I, Item 1 of this report for any recently issued or adopted accounting standards.
Critical Accounting Policies and Estimates
Information regarding our critical accounting policies and estimates is contained in Part II, Item 7 of our 2020 Form 10-K. During the nine months ended September 30, 2021, there were no significant changes in the application of critical accounting policies.
Material Commitments
There have been no significant changes from our 2020 Form 10-K in our obligations and commitments, other than what is disclosed within Note 4 - Leases and Note 6 - Commitments and Contingencies under Part I, Item 1 of this report.
Cautionary Note Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q contains various statements, including those that express belief, expectation, or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plan,” “will,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.
Forward-looking statements include statements related to, among other things:
•the Company's business strategies;
•reserves estimates;
•estimated sales volumes;
•amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;
•ability to modify future capital expenditures;
•anticipated costs;
•compliance with debt covenants;
•ability to fund and satisfy obligations related to ongoing operations;
•compliance with government regulations, including environmental, health, and safety regulations and liabilities thereunder;
•adequacy of gathering systems and continuous improvement of such gathering systems;
•impact from the lack of available gathering systems and processing facilities in certain areas;
•impact of any pandemic or other public health epidemic, including the ongoing COVID-19 pandemic;
•natural gas, oil, and natural gas liquid prices and factors affecting the volatility of such prices;
•impact of lower commodity prices;
•sufficiency of impairments;
•the ability to use derivative instruments to manage commodity price risk and ability to use such instruments in the future;
•our drilling inventory and drilling intentions;
•impact of potentially disruptive technologies;
•our estimated revenue gains and losses;
•the timing and success of specific projects;
•our implementation of standard and long reach laterals;
•our use of multi-well pads to develop the Niobrara and Codell formations;
•intention to continue to optimize enhanced completion techniques and well design changes;
•stated working interest percentages;
•management and technical team;
•outcomes and effects of litigation, claims, and disputes;
•primary sources of future production growth;
•full delineation of the Niobrara B, C, and Codell benches in our legacy, French Lake, and northern acreage;
•our ability to replace oil and natural gas reserves;
•our ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking;
•impact of recently issued accounting pronouncements;
•impact of the loss a single customer or any purchaser of our products;
•timing and ability to meet certain volume commitments related to purchase and transportation agreements;
•the impact of customary royalty interests, overriding royalty interests, obligations incident to operating agreements, liens for current taxes, and other industry-related constraints;
•our financial position;
•our cash flow and liquidity;
•the adequacy of our insurance;
•the expected timetable for completing the XOG Merger and the Crestone Peak Merger, the results, effects, benefits and synergies of the mergers, future opportunities for the combined company, other plans and expectations with respect to the mergers, and the anticipated impact of the mergers on the combined company’s results of operations, financial position, growth opportunities and competitive position; and
•other statements concerning our operations, economic performance, and financial condition.
We have based these forward-looking statements on certain assumptions and analyses we have made in light of our experience and our perception of historical trends, current conditions, and expected future developments as well as other factors we believe are appropriate under the circumstances. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. The actual results or developments anticipated by these forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, and may not be realized or, even if substantially realized, may not have the expected consequences. Actual results could differ materially from those expressed or implied in the forward-looking statements.
Factors that could cause actual results to differ materially include, but are not limited to, the following:
•the risk factors discussed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2020 and in Part II, Item 1A of this report;
•further declines or volatility in the prices we receive for our oil, natural gas liquids, and natural gas;
•general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;
•the effects of disruption of our operations or excess supply of oil and natural gas due to the COVID-19 pandemic and the actions by certain oil and natural gas producing countries;
•the scope, duration and severity of the COVID-19 pandemic, including any recurrence, as well as the timing of the economic recovery following the pandemic;
•ability of our customers to meet their obligations to us;
•our access to capital;
•our ability to generate sufficient cash flow from operations, borrowings, or other sources to enable us to fully develop our undeveloped acreage positions;
•the presence or recoverability of estimated oil and natural gas reserves and the actual future sales volume rates and associated costs;
•uncertainties associated with estimates of proved oil and gas reserves;
•the possibility that the industry may be subject to future local, state, and federal regulatory or legislative actions (including additional taxes and changes in environmental regulation);
•environmental risks;
•seasonal weather conditions;
•lease stipulations;
•drilling and operating risks, including the risks associated with the employment of horizontal drilling and completion techniques;
•our ability to acquire adequate supplies of water for drilling and completion operations;
•availability of oilfield equipment, services, and personnel;
•exploration and development risks;
•operational interruption of centralized gas and oil processing facilities;
•competition in the oil and natural gas industry;
•management’s ability to execute our plans to meet our goals;
•our ability to attract and retain key members of our senior management and key technical employees;
•our ability to maintain effective internal controls;
•access to adequate gathering systems and pipeline take-away capacity;
•our ability to secure adequate processing capacity for natural gas we produce, to secure adequate transportation for oil, natural gas, and natural gas liquids we produce, and to sell the oil, natural gas, and natural gas liquids at market prices;
•costs and other risks associated with perfecting title for mineral rights in some of our properties;
•continued hostilities in the Middle East, South America, and other sustained military campaigns or acts of terrorism or sabotage; and
•other economic, competitive, governmental, legislative, regulatory, geopolitical, and technological factors that may negatively impact our businesses, operations, or pricing.
All forward-looking statements speak only as of the date of this report. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions, and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions, or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under Part II, Item 1A. Risk Factors and Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Oil and Natural Gas Price Risk
Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for oil and natural gas, the global supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels, local and global politics, and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities.
Commodity Derivative Contracts
Our primary commodity risk management objective is to protect the Company’s balance sheet via the reduction in cash flow volatility. We enter into derivative contracts for oil, natural gas, and natural gas liquids using NYMEX futures or over-the-counter derivative financial instruments. The types of derivative instruments that we use include swaps, collars, and puts.
Upon settlement of the contract(s), if the relevant market commodity price exceeds our contracted swap price, or the collar’s ceiling strike price, we are required to pay our counterparty the difference for the volume of production associated with the contract. Generally, this payment is made up to 15 business days prior to the receipt of cash payments from our customers. This could have an adverse impact on our cash flows for the period between derivative settlements and payments for revenue earned.
While we may reduce the potential negative impact of lower commodity prices, we may also be prevented from realizing the benefits of favorable commodity price changes.
Presently, our derivative contracts have been executed with eight counterparties, all of which are members of our Credit Facility syndicate. We enter into contracts with counterparties whom we believe are well capitalized. However, if our counterparties fail to perform their obligations under the contracts, we could suffer financial loss.
Please refer to the Note 10 - Derivatives in Part I, Item 1 of this report for summary derivative activity tables.
Interest Rates
As of September 30, 2021 and the filing date of this report, we had $60.0 million and zero, respectively, outstanding under our Credit Facility. Borrowings under our Credit Facility bear interest at a fluctuating rate that is tied to an adjusted Base Rate or LIBOR, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flow. As of September 30, 2021, and through the filing date of this report, the Company was in compliance with all financial and non-financial covenants in the Credit Facility.
Counterparty and Customer Credit Risk
In connection with our derivatives activity, we have exposure to financial institutions in the form of derivative transactions. Eight members of our Credit Facility syndicate are counterparties on our derivative instruments currently in place and currently have investment grade credit ratings.
We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review the credit rating, payment history, and financial resources of our customers, but we do not require our customers to post collateral.
Marketability of Our Production
The marketability of our production depends in part upon the availability, proximity, and capacity of third-party refineries, access to regional trucking, pipeline, and rail infrastructure, natural gas gathering systems, and processing facilities. We deliver crude oil and natural gas produced through trucking services, pipelines, and rail facilities that we do not own. The lack of availability or capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.
A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of accidents, weather, or field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow.
Currently, there are no pipeline systems that service wells in our French Lake area of the Wattenberg Field. If neither we nor a third-party constructs the required pipeline system, we may not be able to fully test or develop our resources in French Lake.
There have not been material changes to the interest rate risk analysis or oil and gas price sensitivity analysis disclosed in our Annual Report on Form 10-K for the year ended December 31, 2020.
