ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview of Our Business
We are a Fort Worth, Texas-based independent natural gas, natural gas liquids (NGLs) and crude oil and condensate company primarily engaged in the exploration, development and acquisition of natural gas properties in the Appalachian region of the United States. We operate in one segment and have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We measure financial performance as a single enterprise and not on a geographical or an area-by-area basis.
Our overarching business objective is to build stockholder value through returns-focused development of natural gas properties. Our strategy to achieve our business objective is to generate consistent cash flows from reserves and production through internally generated drilling projects occasionally coupled with complementary acquisitions and divestitures of non-core assets. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas, NGLs and oil and on our ability to economically find, develop, acquire, produce and market these reserves. Commodity prices have been and are expected to remain volatile. Our primary near-term focus includes the following:
•operate safely while being good stewards of the environment;
•achieve competitive returns on investments;
•manage liquidity and further improve financial strength;
•focus on organic opportunities through disciplined capital investments;
•improve operational efficiencies and economic returns;
•reduce emissions and target net-zero Scope 1 and Scope 2 greenhouse gas emissions by year-end 2025;
•attract and retain quality employees; and
•align employee incentives with our stockholders’ interests and key business objectives.
We prepare our financial statements in conformity with U.S. GAAP which requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved reserves. We use the successful efforts method of accounting for our natural gas, NGLs and oil activities.
Prices for natural gas, NGLs and oil fluctuate widely and affect:
•revenues, profitability and cash flow;
•the quantity of natural gas, NGLs and oil we can economically produce;
•the quantity of natural gas, NGLs and oil shown as proved reserves;
•the amount of cash flows available for reinvestment; and
•our ability to borrow and raise additional capital.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the preceding consolidated financial statements and notes in Item 1.
Market Conditions
As we begin 2023, we believe we are positioned for sustainable long-term success. We continue to monitor the impact of the actions of OPEC and other large producing nations, the Russia-Ukraine conflict, global inventories of oil and natural gas, future monetary policy and governmental policies aimed at transitioning towards lower carbon energy and we expect prices for some or all of the commodities we produce to remain volatile. For the short-term, natural gas prices declined based on the relatively mild winter and down time at an LNG export facility. Longer term natural gas futures have remained strong based on market expectations that associated gas-related activity in oil basins and dry gas basin activity will show modest rates of growth when compared with the past due to infrastructure constraints, capital discipline and core inventory exhaustion. In addition, the global energy crisis further highlighted the low cost and low emissions shale gas resource base in North America, supporting continued strong structural demand growth for U.S. liquified natural gas exports, domestic industrial gas demand and power generation. Other factors such as geopolitical disruptions, supply chain disruptions, cost inflation and the pace and
24
extent of tightening global monetary policy may impact the supply and demand for oil, natural gas and NGLs. We continue to assess and monitor the impact and consequences of these factors on our operations.
While expected commodity prices have declined in 2023 compared to prior year, we believe market data supports a positive outlook given significant new demand is currently under construction. Our reduced debt levels combined with risk reduction through hedging have us well positioned within the industry.
Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Natural gas, NGLs and oil benchmarks decreased in first quarter 2023 when compared to the same period of 2022. As a result, we experienced a decrease in price realizations. The following table lists related benchmarks for natural gas, oil and NGLs composite prices for the three months ended March 31, 2023 and 2022:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2023 |
|
|
2022 |
|
Benchmarks: |
|
|
|
|
|
|
Average NYMEX prices (a) |
|
|
|
|
|
|
Natural gas (per mcf) |
|
$ |
3.46 |
|
|
$ |
4.89 |
|
Oil (per bbl) |
|
|
76.07 |
|
|
|
94.93 |
|
Mont Belvieu NGLs composite (per gallon) (b) |
|
|
0.62 |
|
|
|
0.97 |
|
|
|
(a) |
Based on weighted average of bid week prompt month prices on the New York Mercantile Exchange. |
(b) |
Based on our estimated NGLs product composition per barrel. |
Our price realizations (not including the impact of our derivatives) may differ from these benchmarks for many reasons, including quality, location or production being sold at different indices.
Consolidated Results of Operations
Overview of First Quarter 2023 Results
During first quarter 2023, we recognized net income of $481.4 million, or $1.95 per diluted common share compared to a loss of $456.8 million, or $1.86 per diluted common share during first quarter 2022. The higher net income in first quarter 2023 compared to first quarter 2022 reflects the impact of lower commodity prices on our reported derivative fair value income (loss) partially offset by the impact of lower commodity prices on our natural gas, NGLs and oil sales. See page 29 for more information on our derivative fair value income (loss).
For first quarter 2023, we experienced a decrease in revenue from the sale of natural gas, NGLs and oil due to a 22% decrease in net realized prices (average prices including all derivative settlements and third-party transportation costs paid by us) when compared to the same quarter of 2022 somewhat offset by slightly higher production volumes. Daily production averaged 2.1 Bcfe in both first quarter 2023 and 2022.
Our first quarter 2023 financial and operating performance included the following results:
•cash flow from operating activities increased $68.5 million from first quarter 2022;
•paid $19.3 million of dividends, or $0.08 per share;
•repurchased $7.8 million of our common stock;
•enhanced liquidity with the accumulation of cash totaling $227.6 million;
•revenue from the sale of natural gas, NGLs and oil decreased 29% from the same period of 2022 with a 31% decrease in average realized prices (before cash settlements on our derivatives);
•revenue from the sale of natural gas, NGLs and oil (including cash settlements on our derivatives) decreased 14% from the same period of 2022;
•transportation, gathering, processing and compression per mcfe was $1.48 in first quarter 2023 compared to $1.60 in the same period of 2022;
•direct operating expense per mcfe was $0.14 in first quarter 2023 compared to $0.11 in the same period of 2022 primarily due to higher production enhancing workover projects and higher water handling/hauling costs;
•general and administrative expense per mcfe decreased 4% from same period of 2022 primarily due to the impact of higher production volumes; and
25
•reduced depletion, depreciation and amortization (“DD&A”) rate per mcfe by 2% from the same period of 2022.
Our cash flow from operating activities in first quarter 2023 was $475.0 million, an increase of $68.5 million from first quarter 2022 with a favorable impact from the change in working capital partially offset by lower commodity prices.
Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations
Our revenues vary primarily as a result of changes in realized commodity prices and production volumes. Our revenues are generally recognized when control of the product is transferred to the customer and collectability is reasonably assured. In first quarter 2023, natural gas, NGLs and oil sales decreased 29% compared to first quarter 2022 with a 31% decrease in average realized prices (before cash settlements on our derivatives) partially offset by a 3% increase in production. The following table illustrates the primary components of natural gas, NGLs and oil sales for the three months ended March 31, 2023 and 2022 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2023 |
|
|
2022 |
|
|
Change |
|
|
% |
|
Natural gas, NGLs and oil sales |
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
$ |
441,580 |
|
|
$ |
629,923 |
|
|
$ |
(188,343 |
) |
|
|
(30 |
)% |
NGLs |
|
256,440 |
|
|
|
338,369 |
|
|
|
(81,929 |
) |
|
|
(24 |
)% |
Oil |
|
38,262 |
|
|
|
64,059 |
|
|
|
(25,797 |
) |
|
|
(40 |
)% |
Total natural gas, NGLs and oil sales |
$ |
736,282 |
|
|
$ |
1,032,351 |
|
|
$ |
(296,069 |
) |
|
|
(29 |
)% |
Our production is determined by drilling success which offsets the natural decline of our natural gas and oil reserves through production. Our production for the three months ended March 31, 2023 and 2022 is set forth in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2023 |
|
|
2022 |
|
|
Change |
|
|
% |
|
Production (a) |
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf) |
|
133,646,064 |
|
|
|
131,250,337 |
|
|
|
2,395,727 |
|
|
|
2 |
% |
NGLs (bbls) |
|
9,289,739 |
|
|
|
8,453,445 |
|
|
|
836,294 |
|
|
|
10 |
% |
Crude oil (bbls) |
|
573,036 |
|
|
|
730,462 |
|
|
|
(157,426 |
) |
|
|
(22 |
)% |
Total (mcfe) (b) |
|
192,822,714 |
|
|
|
186,353,779 |
|
|
|
6,468,935 |
|
|
|
3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production (a) |
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf) |
|
1,484,956 |
|
|
|
1,458,337 |
|
|
|
26,619 |
|
|
|
2 |
% |
NGLs (bbls) |
|
103,219 |
|
|
|
93,927 |
|
|
|
9,292 |
|
|
|
10 |
% |
Crude oil (bbls) |
|
6,367 |
|
|
|
8,116 |
|
|
|
(1,749 |
) |
|
|
(22 |
)% |
Total (mcfe) (b) |
|
2,142,475 |
|
|
|
2,070,598 |
|
|
|
71,877 |
|
|
|
3 |
% |
|
|
(a) |
Represents volumes sold regardless of when produced. |
(b) |
Oil and NGLs volumes are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices. |
26
Our average realized price received (including all derivative settlements and third-party transportation costs) during first quarter 2023 was $2.52 per mcfe compared to $3.23 per mcfe in first quarter 2022. We believe computed final realized prices should include the total impact of transportation, gathering, processing and compression expense. Our average realized price (including all derivative settlements and third-party transportation costs) calculation also includes all cash settlements for derivatives. Average realized prices (excluding derivative settlements) do not include derivative settlements or third-party transportation costs which are reported in transportation, gathering, processing and compression expense in the accompanying consolidated statements of operations. Average realized prices (excluding derivative settlements) do include transportation costs where we receive net revenue proceeds from purchasers. Average realized price calculations for three months ended March 31, 2023 and 2022 are shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2023 |
|
|
2022 |
|
|
Change |
|
|
% |
|
Average Prices |
|
|
|
|
|
|
|
|
|
|
|
Average realized prices (excluding derivative settlements): |
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per mcf) |
$ |
3.30 |
|
|
$ |
4.80 |
|
|
$ |
(1.50 |
) |
|
|
(31 |
)% |
NGLs (per bbl) |
|
27.60 |
|
|
|
40.03 |
|
|
|
(12.43 |
) |
|
|
(31 |
)% |
Crude oil and condensate (per bbl) |
|
66.77 |
|
|
|
87.70 |
|
|
|
(20.93 |
) |
|
|
(24 |
)% |
Total (per mcfe) (a) |
|
3.82 |
|
|
|
5.54 |
|
|
|
(1.72 |
) |
|
|
(31 |
)% |
Average realized prices (including all derivative settlements): |
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per mcf) |
$ |
3.58 |
|
|
$ |
4.04 |
|
|
$ |
(0.46 |
) |
|
|
(11 |
)% |
NGLs (per bbl) |
|
27.60 |
|
|
|
38.57 |
|
|
|
(10.97 |
) |
|
|
(28 |
)% |
Crude oil and condensate (per bbl) |
|
62.96 |
|
|
|
58.46 |
|
|
|
4.50 |
|
|
|
8 |
% |
Total (per mcfe) (a) |
|
4.00 |
|
|
|
4.83 |
|
|
|
(0.83 |
) |
|
|
(17 |
)% |
Average realized prices (including all derivative settlements and third-party transportation costs paid by Range): |
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per mcf) |
$ |
2.44 |
|
|
$ |
2.82 |
|
|
$ |
(0.38 |
) |
|
|
(13 |
)% |
NGLs (per bbl) |
|
13.32 |
|
|
|
22.32 |
|
|
|
(9.00 |
) |
|
|
(40 |
)% |
Crude oil and condensate (per bbl) |
|
62.64 |
|
|
|
58.44 |
|
|
|
4.20 |
|
|
|
7 |
% |
Total (per mcfe) (a) |
|
2.52 |
|
|
|
3.23 |
|
|
|
(0.71 |
) |
|
|
(22 |
)% |
|
|
(1) |
Oil and NGLs volumes are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices. |
Realized prices include the impact of basis differentials and gains or losses realized from our basis hedging. The prices we receive for our natural gas can be more or less than the NYMEX price because of adjustments for delivery location, relative quality and other factors. The following table provides this impact on a per mcf basis:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2023 |
|
|
2022 |
|
Average natural gas differentials below NYMEX |
|
$ |
(0.16 |
) |
|
$ |
(0.09 |
) |
Realized gains on basis hedging |
|
$ |
0.02 |
|
|
$ |
0.12 |
|
The following tables reflect our production and average realized commodity prices (excluding derivative settlements and third-party transportation costs paid by Range) (in thousands, except prices):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2022 |
|
|
Price Variance |
|
|
Volume Variance |
|
|
2023 |
|
Natural gas |
|
|
|
|
|
|
|
|
|
|
|
Price (per mcf) |
$ |
4.80 |
|
|
$ |
(1.50 |
) |
|
$ |
— |
|
|
$ |
3.30 |
|
Production (Mmcf) |
|
131,250 |
|
|
|
— |
|
|
|
2,396 |
|
|
|
133,646 |
|
Natural gas sales |
$ |
629,923 |
|
|
$ |
(199,841 |
) |
|
$ |
11,498 |
|
|
$ |
441,580 |
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2022 |
|
|
Price Variance |
|
|
Volume Variance |
|
|
2023 |
|
NGLs |
|
|
|
|
|
|
|
|
|
|
|
|
Price (per bbl) |
|
$ |
40.03 |
|
|
$ |
(12.43 |
) |
|
$ |
— |
|
|
$ |
27.60 |
|
Production (Mbbls) |
|
|
8,453 |
|
|
|
— |
|
|
|
837 |
|
|
|
9,290 |
|
NGLs sales |
|
$ |
338,369 |
|
|
$ |
(115,404 |
) |
|
$ |
33,475 |
|
|
$ |
256,440 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2022 |
|
|
Price Variance |
|
|
Volume Variance |
|
|
2023 |
|
Crude oil |
|
|
|
|
|
|
|
|
|
|
|
|
Price (per bbl) |
|
$ |
87.70 |
|
|
$ |
(20.93 |
) |
|
$ |
— |
|
|
$ |
66.77 |
|
Production (Mbbls) |
|
|
730 |
|
|
|
— |
|
|
|
(157 |
) |
|
|
573 |
|
Crude oil sales |
|
$ |
64,059 |
|
|
$ |
(11,991 |
) |
|
$ |
(13,806 |
) |
|
$ |
38,262 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2022 |
|
|
Price Variance |
|
|
Volume Variance |
|
|
2023 |
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
Price (per mcfe) |
$ |
5.54 |
|
|
$ |
(1.72 |
) |
|
$ |
— |
|
|
$ |
3.82 |
|
Production (Mmcfe) |
|
186,354 |
|
|
|
— |
|
|
|
6,469 |
|
|
|
192,823 |
|
Total natural gas, NGLs and oil sales |
$ |
1,032,351 |
|
|
$ |
(331,905 |
) |
|
$ |
35,836 |
|
|
$ |
736,282 |
|
Transportation, gathering, processing and compression expense was $285.5 million in first quarter 2023 compared to $297.8 million in first quarter 2022. These third-party costs are lower in first quarter 2023 when compared to first quarter 2022 due to lower fuel prices, lower electricity costs and the impact of lower NGLs prices which result in lower processing costs. We have included these costs in the calculation of average realized prices (including all derivative settlements and third-party transportation expenses paid by Range). The following table summarizes transportation, gathering, processing and compression expense for the three months ended March 31, 2023 and 2022 on a per mcf and per barrel basis (in thousands, except for costs per unit):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2023 |
|
|
2022 |
|
|
Change |
|
|
% |
|
Transportation, gathering, processing and compression |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
$ |
152,589 |
|
|
$ |
160,436 |
|
|
$ |
(7,847 |
) |
|
|
(5 |
)% |
NGLs |
|
|
132,712 |
|
|
|
137,340 |
|
|
|
(4,628 |
) |
|
|
(3 |
)% |
Oil |
|
|
182 |
|
|
|
11 |
|
|
|
171 |
|
|
|
1,555 |
% |
Total |
|
$ |
285,483 |
|
|
$ |
297,787 |
|
|
$ |
(12,304 |
) |
|
|
(4 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per mcf) |
|
$ |
1.14 |
|
|
$ |
1.22 |
|
|
$ |
(0.08 |
) |
|
|
(7 |
)% |
NGLs (per bbl) |
|
$ |
14.28 |
|
|
$ |
16.25 |
|
|
$ |
(1.97 |
) |
|
|
(12 |
)% |
Oil (per bbl) |
|
$ |
0.32 |
|
|
$ |
0.02 |
|
|
$ |
0.30 |
|
|
|
1,500 |
% |
28
Derivative fair value income (loss) was income of $368.0 million in first quarter 2023 compared to a loss of $939.1 million in first quarter 2022. All of our derivatives are accounted for using the mark-to-market accounting method. Mark-to-market accounting treatment can result in more volatility of our revenues as the change in the fair value of our commodity derivative positions is included in total revenue. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Gains on our derivatives generally indicate potentially lower wellhead revenues in the future while losses indicate potentially higher future wellhead revenues. The following table summarizes the impact of our commodity derivatives for the three months ended March 31, 2023 and 2022 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2023 |
|
|
2022 |
|
Derivative fair value income (loss) per consolidated statements of operations |
|
$ |
367,967 |
|
|
$ |
(939,057 |
) |
|
|
|
|
|
|
|
Non-cash fair value income (loss): (1) |
|
|
|
|
|
|
Natural gas derivatives |
|
$ |
327,380 |
|
|
$ |
(742,253 |
) |
Oil derivatives |
|
|
10,039 |
|
|
|
(53,385 |
) |
NGLs derivatives |
|
|
— |
|
|
|
(18,290 |
) |
Freight derivatives |
|
|
— |
|
|
|
(114 |
) |
Divestiture contingent consideration |
|
|
(3,920 |
) |
|
|
8,120 |
|
Total non-cash fair value income (loss) (1) |
|
$ |
333,499 |
|
|
$ |
(805,922 |
) |
|
|
|
|
|
|
|
Net cash receipt (payment) on derivative settlements: |
|
|
|
|
|
|
Natural gas derivatives |
|
$ |
36,650 |
|
|
$ |
(99,458 |
) |
Oil derivatives |
|
|
(2,182 |
) |
|
|
(21,359 |
) |
NGLs derivatives |
|
|
— |
|
|
|
(12,318 |
) |
Total net cash receipt (payment) |
|
$ |
34,468 |
|
|
$ |
(133,135 |
) |
|
|
(1) |
Non-cash fair value adjustments on commodity derivatives is a non-U.S. GAAP measure. Non-cash fair value adjustments on commodity derivatives only represent the net change between periods of the fair market values of commodity derivative positions and exclude the impact of settlements on commodity derivatives during the period. We believe that non-cash fair value adjustments on commodity derivatives is a useful supplemental disclosure to differentiate non-cash fair market value adjustments from settlements on commodity derivatives during the period. Non-cash fair value adjustments on commodity derivatives is not a measure of financial or operating performance under U.S. GAAP, nor should it be considered a substitute for derivative fair value income or loss as reported in our consolidated statements of operations. This also includes the change in fair value of our divestiture contingent consideration. |
Brokered natural gas, marketing and other revenue in first quarter 2023 was $82.1 million compared to $87.4 million in first quarter 2022 which is the result of significantly lower broker sales prices somewhat offset by significantly higher broker sales volumes (volumes not related to our production). The three months ended March 31, 2023 includes the receipt of a $3.6 million make-whole payment. We continue to optimize our transportation portfolio using these volumes. See also Brokered natural gas and marketing expense below for more information on our net brokered margin.
Operating Costs per Mcfe
We believe some of our expense fluctuations are best analyzed on a unit-of-production or per mcfe basis. The following table presents information about certain of our expenses on a per mcfe basis for the three months ended March 31, 2023 and 2022:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2023 |
|
|
2022 |
|
|
Change |
|
|
% |
|
Direct operating expense |
$ |
0.14 |
|
|
$ |
0.11 |
|
|
$ |
0.03 |
|
|
|
27 |
% |
Taxes other than income |
|
0.04 |
|
|
|
0.04 |
|
|
|
— |
|
|
|
— |
% |
General and administrative expense |
|
0.22 |
|
|
|
0.23 |
|
|
|
(0.01 |
) |
|
|
(4 |
)% |
Interest expense |
|
0.17 |
|
|
|
0.25 |
|
|
|
(0.08 |
) |
|
|
(32 |
)% |
Depletion, depreciation and amortization expense |
|
0.45 |
|
|
|
0.46 |
|
|
|
(0.01 |
) |
|
|
(2 |
)% |
29
Direct operating expense was $27.0 million in first quarter 2023 compared to $20.3 million in first quarter 2022. Direct operating expenses include normally recurring expenses to operate and produce our wells, non-recurring well workovers and repair-related expenses. Our direct operating costs increased in first quarter 2023 primarily due to higher workover costs, higher water handling/hauling costs and higher contract labor and services. Our costs for services, labor and supplies have increased due to increased demand for those items, supply chain disruptions and inflation. Our production volumes were slightly higher in first quarter 2023 compared to the same period of the prior year. We incurred $2.9 million of workover costs in first quarter 2023 compared to $881,000 in first quarter 2022. These costs are expected to enhance production from existing wells. On a per mcfe basis, direct operating expense was $0.14 in first quarter 2023 compared to $0.11 in the same quarter of the prior year due to higher workover costs and higher water handling/hauling costs. The following table summarizes direct operating expense per mcfe for the three months ended March 31, 2023 and 2022:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2023 |
|
|
2022 |
|
|
Change |
|
|
% |
|
Direct operating |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
$ |
0.12 |
|
|
$ |
0.11 |
|
|
$ |
0.01 |
|
|
|
9 |
% |
Workovers |
|
|
0.02 |
|
|
|
— |
|
|
|
0.02 |
|
|
|
100 |
% |
Stock-based compensation |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
% |
Total direct operating expense |
|
$ |
0.14 |
|
|
$ |
0.11 |
|
|
$ |
0.03 |
|
|
|
27 |
% |
Taxes other than income expense is predominately comprised of the Pennsylvania impact fee which is paid based on market commodity prices. In February 2012, the Commonwealth of Pennsylvania enacted an “impact fee” which functions as a tax on unconventional natural gas and oil production from the Marcellus Shale in Pennsylvania. This impact fee was $6.8 million in first quarter 2023 compared to $6.6 million in first quarter 2022. The impact fee is based on drilling activities and is adjusted based on prevailing natural gas prices. This category also includes franchise, real estate and other taxes. The following table summarizes taxes other than income per mcfe for the three months ended March 31, 2023 and 2022:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2023 |
|
|
2022 |
|
|
Change |
|
|
% |
|
Taxes other than income |
|
|
|
|
|
|
|
|
|
|
|
Impact fee |
$ |
0.04 |
|
|
$ |
0.04 |
|
|
$ |
— |
|
|
|
— |
% |
Other |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
% |
Total taxes other than income |
$ |
0.04 |
|
|
$ |
0.04 |
|
|
$ |
— |
|
|
|
— |
% |
General and administrative (G&A) expense was $43.1 million in first quarter 2023 compared to $42.5 million in first quarter 2022. The first quarter 2023 increase of $609,000 when compared to the same period of 2022 is primarily due to higher salaries and benefits of $3.0 million partially offset by lower stock-based compensation and lower legal fees. On a per mcfe basis, first quarter 2023 G&A expense was 4% lower than first quarter 2022 primarily due to the impact of higher production volumes and lower stock-based compensation. The following table summarizes G&A expenses on a per mcfe basis for the three months ended March 31, 2023 and 2022:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2023 |
|
|
2022 |
|
|
Change |
|
|
% |
|
General and administrative |
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative |
|
$ |
0.17 |
|
|
$ |
0.17 |
|
|
$ |
— |
|
|
|
— |
% |
Stock-based compensation |
|
|
0.05 |
|
|
|
0.06 |
|
|
|
(0.01 |
) |
|
|
(17 |
)% |
Total general and administrative expense |
|
$ |
0.22 |
|
|
$ |
0.23 |
|
|
$ |
(0.01 |
) |
|
|
(4 |
)% |
30
Interest expense was $32.2 million in first quarter 2023 compared to $47.2 million in first quarter 2022. The following table presents information about interest expense per mcfe for the three months ended March 31, 2023 and 2022:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2023 |
|
|
2022 |
|
|
Change |
|
|
% |
|
Bank credit facility |
$ |
0.02 |
|
|
$ |
0.02 |
|
|
$ |
— |
|
|
|
— |
% |
Senior notes |
|
0.14 |
|
|
|
0.22 |
|
|
|
(0.08 |
) |
|
|
(36 |
)% |
Amortization of deferred financing costs and other |
|
0.01 |
|
|
|
0.01 |
|
|
|
— |
|
|
|
— |
% |
Total interest expense |
$ |
0.17 |
|
|
$ |
0.25 |
|
|
$ |
(0.08 |
) |
|
|
(32 |
)% |
Average debt outstanding ($000s) |
$ |
1,881,965 |
|
|
$ |
2,782,406 |
|
|
$ |
(900,441 |
) |
|
|
(32 |
)% |
Average interest rate (a) |
|
6.6 |
% |
|
|
6.5 |
% |
|
|
0.1 |
% |
|
|
2 |
% |
|
|
(a) |
Includes commitment fees but excludes debt issue costs and amortization of discounts and premiums. |
On an absolute basis, the decrease in interest expense for first quarter 2023 from the same period of 2022 was primarily due to lower overall average outstanding debt balances. Average debt outstanding on the bank credit facility for first quarter 2023 was $32.0 million compared to $65.3 million in first quarter 2022 and the weighted average interest rate on the bank credit facility was 8.4% in first quarter 2023 compared to 2.5% in first quarter 2022.
Depletion, depreciation and amortization expense was $86.6 million in first quarter 2023 compared to $85.6 million in first quarter 2022. This increase is due to a 3% increase in production volumes partially offset by a 2% decrease in depletion rates. Depletion expense, the largest component of DD&A expense, was $0.44 per mcfe in first quarter 2023 compared to $0.45 per mcfe in first quarter 2022. We have historically adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and at other times during the year when circumstances indicate there has been a significant change in reserves or costs. The following table summarizes DD&A expense per mcfe for the three months ended March 31, 2023 and 2022:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2023 |
|
|
2022 |
|
|
Change |
|
|
% |
|
DD&A |
|
|
|
|
|
|
|
|
|
|
|
|
Depletion and amortization |
|
$ |
0.44 |
|
|
$ |
0.45 |
|
|
$ |
(0.01 |
) |
|
|
(2 |
)% |
Depreciation |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
% |
Accretion and other |
|
|
0.01 |
|
|
|
0.01 |
|
|
|
— |
|
|
|
— |
% |
Total DD&A expense |
|
$ |
0.45 |
|
|
$ |
0.46 |
|
|
$ |
(0.01 |
) |
|
|
(2 |
)% |
Other Operating Expenses
Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, brokered natural gas and marketing expense, exploration expense, abandonment and impairment of unproved properties, exit and termination costs, deferred compensation plan expenses and loss or gain on early extinguishment of debt. Stock-based compensation includes the amortization of restricted stock grants and PSUs. The following table details the allocation of stock-based compensation to functional expense categories for the three months ended March 31, 2023 and 2022 (in thousands):
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2023 |
|
|
2022 |
|
Direct operating expense |
$ |
415 |
|
|
$ |
349 |
|
Brokered natural gas and marketing expense |
|
661 |
|
|
|
519 |
|
Exploration expense |
|
320 |
|
|
|
452 |
|
General and administrative expense |
|
9,600 |
|
|
|
11,573 |
|
Total stock-based compensation |
$ |
10,996 |
|
|
$ |
12,893 |
|
31
Brokered natural gas and marketing expense was $67.1 million in first quarter 2023 compared to $93.1 million in first quarter 2022 due to significantly lower commodity prices partially offset by significantly higher broker purchase volumes (volumes not related to our production). Other marketing revenue for the three months ended March 31, 2023 includes the receipt of a $3.6 million make-whole payment. The following table details our brokered natural gas, marketing and other net margin for the three months ended March 31, 2023 and 2022 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2023 |
|
|
2022 |
|
|
Change |
|
|
% |
|
Brokered natural gas and marketing |
|
|
|
|
|
|
|
|
|
|
|
Brokered natural gas sales |
$ |
75,060 |
|
|
$ |
84,062 |
|
|
$ |
(9,002 |
) |
|
|
(11 |
)% |
Brokered NGLs sales |
|
368 |
|
|
|
1,640 |
|
|
|
(1,272 |
) |
|
|
(78 |
)% |
Other marketing revenue |
|
6,683 |
|
|
|
1,740 |
|
|
|
4,943 |
|
|
|
284 |
% |
Brokered natural gas purchases (1) |
|
(64,275 |
) |
|
|
(89,194 |
) |
|
|
24,919 |
|
|
|
28 |
% |
Brokered NGLs purchases |
|
(340 |
) |
|
|
(1,647 |
) |
|
|
1,307 |
|
|
|
79 |
% |
Other marketing expense |
|
(2,453 |
) |
|
|
(2,282 |
) |
|
|
(171 |
) |
|
|
(7 |
)% |
Net brokered natural gas and marketing margin |
$ |
15,043 |
|
|
$ |
(5,681 |
) |
|
$ |
20,724 |
|
|
|
365 |
% |
|
|
(1) |
Includes transportation costs. |
Exploration expense was $4.6 million in first quarter 2023 compared to $4.7 million in first quarter 2022 due to lower delay rentals and other expense. The following table details our exploration expense for the three months ended March 31, 2023 and 2022 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2023 |
|
|
2022 |
|
|
Change |
|
|
% |
|
Exploration |
|
|
|
|
|
|
|
|
|
|
|
Delay rentals and other |
$ |
2,539 |
|
|
$ |
2,943 |
|
|
$ |
(404 |
) |
|
|
(14 |
)% |
Personnel expense |
|
1,575 |
|
|
|
1,305 |
|
|
|
270 |
|
|
|
21 |
% |
Stock-based compensation expense |
|
320 |
|
|
|
452 |
|
|
|
(132 |
) |
|
|
(29 |
)% |
Seismic |
|
170 |
|
|
|
(1 |
) |
|
|
171 |
|
|
NM |
|
Total exploration expense |
$ |
4,604 |
|
|
$ |
4,699 |
|
|
$ |
(95 |
) |
|
|
(2 |
)% |
Abandonment and impairment of unproved properties expense was $7.5 million in first quarter 2023 compared to $2.0 million in first quarter 2022. Abandonment and impairment of unproved properties for first quarter 2023 increased when compared to the same period of 2022 due to higher estimated lease expirations in Pennsylvania.
Exit costs were $12.3 million in first quarter 2023 compared to $11.1 million in first quarter 2022. In first quarter 2023, we recorded $10.3 million accretion expense primarily related to retained liabilities for certain gathering, transportation and processing obligations extending until 2030 compared to accretion expense of $11.1 million in the same quarter of the prior year.
Deferred compensation plan expense was a loss of $9.4 million in first quarter 2023 compared to a loss of $73.3 million in first quarter 2022. This non-cash item relates to the increase or decrease in value of the liability associated with our common stock that is vested and held in our deferred compensation plan. The deferred compensation liability is adjusted to fair value by a charge or a credit to deferred compensation plan expense. Our stock price increased from $25.02 at December 31, 2022 to $26.47 at March 31, 2023. In the same period of the prior year, our stock price increased from $17.83 at December 31, 2021 to $30.38 at March 31, 2022.
Loss on early extinguishment of debt was a loss of $69.2 million in first three months 2022. In first quarter 2022, we announced a call for the redemption of $850.0 million of our outstanding 9.25% senior notes due 2026. The redemption price equaled 106.938% of par plus accrued and unpaid interest. We recognized a loss on early extinguishment of debt in first quarter 2022 of $69.2 million, net of transaction costs and the expensing of the remaining deferred financing costs on the repurchased debt.
32
Income tax expense (benefit) was an expense of $121.9 million in first quarter 2023 compared to benefit of $116.1 million in first quarter 2022. The 2023 and 2022 effective tax rates were different than the statutory tax rate due to state income taxes, equity compensation, valuation allowances and other discrete tax items.
Management’s Discussion and Analysis of Financial Condition, Capital Resources and Liquidity
Cash Flows
Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivatives. Our cash flows from operations are also impacted by changes in working capital. Short-term liquidity needs are satisfied by borrowings under our bank credit facility and/or cash on hand. Because of this, and because our principal source of operating cash flows (proved reserves to be produced in future years) cannot be reported as working capital, we often have low or negative working capital. From time to time, we enter into various derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future natural gas, NGLs and oil production. The production we hedge has varied and will continue to vary from year to year depending on, among other things, our expectation of future commodity prices and capital requirements. Any payments due to counterparties under our derivative contracts should ultimately be funded by prices received from the sale of our production. Production receipts, however, often lag payments to the counterparties. As of March 31, 2023, we have entered into derivative agreements covering 226.1 Bcfe for the remainder of 2023 and 213.4 Bcfe for 2024, not including our basis swaps.
The following table presents sources and uses of cash and cash equivalents for the three months ended March 31, 2023 and 2022 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2023 |
|
|
2022 |
|
Sources of cash and cash equivalents |
|
|
|
|
|
|
Operating activities |
|
$ |
474,956 |
|
|
$ |
406,414 |
|
Disposal of assets |
|
|
660 |
|
|
|
349 |
|
Issuance of senior notes |
|
|
— |
|
|
|
500,000 |
|
Borrowing on credit facility |
|
|
185,000 |
|
|
|
282,000 |
|
Other |
|
|
6,252 |
|
|
|
10,033 |
|
Total sources of cash and cash equivalents |
|
$ |
666,868 |
|
|
$ |
1,198,796 |
|
|
|
|
|
|
|
|
Uses of cash and cash equivalents |
|
|
|
|
|
|
Additions to natural gas properties |
|
$ |
(125,468 |
) |
|
$ |
(90,104 |
) |
Repayment on credit facility |
|
|
(204,000 |
) |
|
|
(282,000 |
) |
Acreage purchases |
|
|
(12,742 |
) |
|
|
(12,599 |
) |
Additions to field service assets |
|
|
(74 |
) |
|
|
(37 |
) |
Repayment of senior and senior subordinated notes |
|
|
— |
|
|
|
(850,000 |
) |
Treasury stock purchases |
|
|
(7,834 |
) |
|
|
(16,199 |
) |
Dividends paid |
|
|
(19,334 |
) |
|
|
— |
|
Debt issuance costs |
|
|
— |
|
|
|
(6,817 |
) |
Other |
|
|
(69,990 |
) |
|
|
(42,531 |
) |
Total uses of cash and cash equivalents |
|
$ |
(439,442 |
) |
|
$ |
(1,300,287 |
) |
Sources of Cash and Cash Equivalents
Cash flows provided from operating activities in first three months 2023 was $475.0 million compared to $406.4 million in first three months 2022. Cash provided from operating activities is largely dependent upon commodity prices and production volumes, net of the effects of settlement of our derivative contracts. The increase in cash provided from operating activities from first three months 2022 to first three months 2023 reflects the impact of a favorable change in working capital (the timing of cash receipts and disbursements) and slightly higher production volumes partially offset by lower realized prices. As of March 31, 2023, we have hedged more than 40% of our projected total production for the remainder of 2023, with more than 50% of our projected natural gas production hedged. Changes in working capital (as reflected in our consolidated statements of cash flows) for first three months 2023 were positive $79.7 million compared to a negative $77.4 million for first three months 2022.
33
Uses of Cash and Cash Equivalents
Additions to natural gas properties for first three months 2023 were consistent with expectations relative to our announced 2023 capital budget. We continue to monitor inflationary pressures given the labor market, commodity prices and supply chain challenges.
Treasury stock purchases for first three months 2023 include the repurchase of 323,000 shares as part of our previously announced stock repurchase program.
Liquidity and Capital Resources
Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan for the foreseeable future. We continue to manage the duration and level of our drilling and completion commitments in order to maintain flexibility with regard to our activity level and capital expenditures. As of March 31, 2023, we had cash on hand in the amount of $227.6 million and availability under our credit facility of $1.2 billion.
Sources of Cash
We expect our 2023 capital program to be funded by cash flows from operations. During the three months ended March 31, 2023, we generated $475.0 million of cash flows from operating activities. As of March 31, 2023, we had approximately $1.4 billion of liquidity, consisting of $1.2 billion available under our bank credit facility and $227.6 million of cash on hand. Our borrowing base can be adjusted as a result of changes in commodity prices, acquisitions or divestitures of proved properties or financing activities. We may draw on our bank credit facility to meet short-term cash requirements.
Although we expect cash flows and capacity under the existing credit facility to be sufficient to fund our expected 2023 capital program, we may also have the option to raise funds through new debt or equity offerings or from other sources of financing. All of our sources of liquidity can be affected by the general conditions of the broader economy, force majeure events and fluctuations in commodity prices, operating costs and volumes produced, all of which affect us and our industry. We have no control over market prices for natural gas, NGLs or oil, although we may be able to influence realized revenues through the use of derivative contracts as part of our commodity price risk management.
Bank Credit Facility
Our bank credit facility is secured by substantially all of our assets. As of March 31, 2023, we had no outstanding borrowings under our bank credit facility and we maintained a borrowing base of $3.0 billion and aggregate lender commitments of $1.5 billion. We also have undrawn letters of credit of $292.3 million as of March 31, 2023. We were in compliance with the applicable covenants under the bank credit facility as of March 31, 2023.
The borrowing base is subject to regular, semi-annual redeterminations and is dependent on a number of factors but primarily the lender’s assessment of our future cash flows. Our scheduled borrowing base redetermination was completed in March 2023 with our borrowing base and commitments reaffirmed.
Our daily weighted-average bank credit facility debt balance was $32.0 million for first three months ended March 31, 2023 compared to $65.3 million for the same period of the prior year. Borrowings under the amended and restated revolving bank credit facility can either be at the alternate base rate (ABR, as defined in the bank credit facility agreement) plus a spread ranging from 0.75% to 1.75% or at the secured overnight financing rate (SOFR, as defined in the bank credit facility agreement) plus a spread ranging from 1.75% to 2.75%. The applicable spread is dependent upon borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our SOFR loans to base rate loans or to convert all or any of the base rate loans to SOFR loans.
Uses of Cash
We use cash for the development, exploration and acquisition of natural gas properties and for the payment of gathering, transportation and processing costs, operating, general and administrative costs, taxes and debt obligations, including interest, dividends and share repurchases. Expenditures for the development, exploration and acquisition of natural gas properties are the primary use of our capital resources. During first three months 2023, we funded $138.3 million of capital expenditures as reported in our consolidated statement of cash flows with operating cash flows. The amount of our future capital expenditures will depend upon a number of factors including our cash flows from operating, investing and financing activities, infrastructure availability, supply and demand fundamentals and our ability to execute our development program. In addition, the impact of commodity prices on investment opportunities, the availability of capital and the timing and results of our development activities may lead to changes in funding requirements for future development. We periodically review our budget to assess changes in current and projected cash flows, debt requirements and other factors.
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We may from time to time repurchase or redeem all or portions of our outstanding debt securities for cash, through exchanges for other securities or a combination of both. Such repurchases or redemptions may be made in open market transactions and will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. Our next significant long-term debt maturity is in the amount of $750.0 million due 2025. As part of our strategy for 2023, we will continue to focus on improving our financial strength.
Our quarterly cash dividend was reinstated in third quarter of 2022. See also Cash Dividend Payments below. During the first three months 2023, we repurchased 400,000 shares of our common stock at an aggregate cost of $9.7 million (including 77,000 shares purchased in March and settled in April). The total remaining share repurchase authorization was approximately $1.1 billion at March 31, 2023.
Shelf Registration
We have a universal shelf registration statement filed with the SEC under which we, as a well-known seasoned issuer for purposes of SEC rules, have the ability to sell an indeterminate amount of various types of debt and equity securities.
Cash Dividend Payments
On March 1, 2023, our board of directors approved a dividend of $0.08 per share payable on March 31, 2023 to stockholders of record at the close of business on March 15, 2023. The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of the board of directors and primarily depends on cash flow, capital expenditures, debt covenants and various other factors.
Cash Contractual Obligations
Our contractual obligations include long-term debt, operating leases, derivative obligations, asset retirement obligations and transportation, processing and gathering commitments including the divestiture contractual commitment. As of March 31, 2023, we do not have any significant off-balance sheet debt or other such unrecorded obligations and we have not guaranteed any debt of any unrelated party. As of March 31, 2023, we had a total of $292.3 million of undrawn letters of credit under our bank credit facility.
Since December 31, 2022, there have been no material changes to our contractual obligations.
Interest Rates
At March 31, 2023, we had approximately $1.9 billion of debt outstanding which bore interest at fixed rates averaging 5.9%. We had no variable rate debt outstanding at March 31, 2023.
Off-Balance Sheet Arrangements
We do not currently utilize any significant off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resource position, or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments, some of which are described above under Cash Contractual Obligations.
Inflation and Changes in Prices
Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas, NGLs and oil prices and the costs to produce our reserves. Natural gas, NGLs and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. Certain of our costs and expenses are affected by general inflation and we expect costs for the remainder of 2023 to continue to be a function of supply and demand.
Forward-Looking Statements
Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements typically contain words such as “anticipates,” “believes,” “expects,” “targets,” “plans,” “estimates,” “predicts,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our current
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forecasts for our existing operations and do not include the potential impact of any future events. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise. For additional risk factors affecting our business, see Item 1A. Risk Factors as set forth in our Annual Report on Form 10-K for the year ended December 31, 2022, as filed with the SEC on February 27, 2023.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, NGLs and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposure. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are U.S. dollar denominated.
Market Risk
We are exposed to market risks related to the volatility of natural gas, NGLs and oil prices. We employ various strategies, including the use of commodity derivative instruments, to manage the risks related to these price fluctuations. These derivative instruments apply to a varying portion of our production and provide only partial price protection. These arrangements can limit the benefit to us of increases in prices but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the derivatives. Realized prices are primarily driven by worldwide prices for oil and regional index prices for North American natural gas production. However, natural gas and NGLs prices are becoming global commodities similar to oil. Natural gas and oil prices have been volatile and unpredictable for many years. Changes in natural gas prices affect us more than changes in oil prices because approximately 65% of our December 31, 2022 proved reserves are natural gas and 2% of proved reserves are oil and condensate. In addition, a portion of our NGLs, which are 33% of proved reserves, are also impacted by changes in oil prices. We are also exposed to market risks related to changes in interest rates. These risks did not change materially from December 31, 2022 to March 31, 2023.
Commodity Price Risk
We use commodity-based derivative contracts to manage exposures to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. At times, certain of our derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. Our derivatives program can also include collars, which establish a minimum floor price and a predetermined ceiling price. Our program may also include a three-way collar which is a combination of three options. At March 31, 2023, our derivative program includes swaps, collars and three-way collars. The fair value of these contracts, represented by the estimated amount that would be realized upon immediate liquidation based on a comparison of the contract price and a reference price, generally NYMEX for natural gas and crude oil or Mont Belvieu for NGLs, as of March 31, 2023, approximated a net unrealized pretax gain of $249.6 million. These contracts expire monthly through December 2024. At March 31, 2023, the following commodity derivative contracts were outstanding, excluding our basis swaps which are discussed below:
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Period |
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Contract Type |
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Volume Hedged |
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Weighted Average Hedge Price |
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Swap |
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Sold Put |
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Floor |
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Ceiling |
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Fair Market Value (in thousands) |
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Natural Gas |
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2023 |
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Swaps |
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354,636 Mmbtu/day |
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$ |
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3.48 |
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$ |
66,000 |
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2023 |
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Collars |
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261,091 Mmbtu/day |
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$ |
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3.40 |
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$ |
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4.52 |
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$ |
57,635 |
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2023 |
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Three-way Collars |
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176,400 Mmbtu/day |
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$ |
2.59 |
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$ |
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3.62 |
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$ |
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4.71 |
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$ |
28,338 |
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2024 |
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Swaps |
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150,000 Mmbtu/day |
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$ |
4.46 |
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$ |
42,917 |
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2024 |
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Collars |
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429,235 Mmbtu/day |
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$ |
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3.51 |
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$ |
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5.65 |
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$ |
56,784 |
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Crude Oil |
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2023 |
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Swaps |
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5,000 bbls/day |
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$ |
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71.28 |
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$ |
(4,525 |
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January-September 2024 |
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Collars |
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832 bbls/day |
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$ |
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80.00 |
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$ |
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90.12 |
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$ |
2,464 |
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We believe NGLs prices are somewhat seasonal, particularly for propane. Therefore, the relationship of NGLs prices to NYMEX WTI (or West Texas Intermediate) will vary due to product components, seasonality and geographic supply and demand. We sell NGLs in several regional and international markets. If we are not able to sell or store NGLs, we may be required to curtail production or shift our drilling activities to dry gas areas.
Currently, the Appalachian region has limited local demand and infrastructure to accommodate ethane. We have agreements where we have contracted to either sell or transport ethane from our Marcellus Shale area. We cannot ensure that these facilities will remain available. If we are not able to sell ethane under at least one of these agreements, we may be required to curtail production or, as we have done in the past, purchase or divert natural gas to blend with our rich residue gas.
Other Commodity Risk
We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. Natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased basis risk. Therefore, in addition to the swaps, collars and three-way collars discussed above, we have entered into natural gas basis swap agreements. The price we receive for our gas production can be more or less than the NYMEX Henry Hub price because of basis adjustments, relative quality and other factors. Basis swap agreements effectively fix the basis adjustments. The fair value of the natural gas basis swaps was a loss of $50.3 million at March 31, 2023 and they settle monthly through December 2026.
At March 31, 2023, we are entitled to receive contingent consideration associated with the sale of our North Louisiana assets, annually through 2023, of up to $21.0 million based on future achievement of certain natural gas and oil prices based on published indexes along with the realized NGLs prices of the buyer. The fair value at March 31, 2023 was a gain of $9.2 million.
The following table shows the fair value of our derivatives and the hypothetical changes in fair value that would result from a 10% and a 25% change in commodity prices at March 31, 2023. We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risks should be mitigated by price changes in the underlying physical commodity (in thousands):
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Hypothetical Change in Fair Value |
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Hypothetical Change in Fair Value |
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Increase in Commodity Price of |
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Decrease in Commodity Price of |
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Fair Value |
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10% |
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25% |
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10% |
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25% |
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Swaps |
$ |
104,392 |
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$ |
(55,387 |
) |
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$ |
(138,468 |
) |
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$ |
55,387 |
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$ |
138,467 |
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Collars |
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116,883 |
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(53,144 |
) |
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(132,385 |
) |
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54,354 |
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140,297 |
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Three-way collars |
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28,338 |
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(5,614 |
) |
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(15,560 |
) |
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5,279 |
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12,099 |
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Basis swaps |
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(50,272 |
) |
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18,262 |
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45,655 |
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(18,262 |
) |
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(45,655 |
) |
Divestiture contingent consideration |
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9,160 |
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1,050 |
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2,490 |
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(1,110 |
) |
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(3,190 |
) |
Our commodity-based derivative contracts expose us to the credit risk of non-performance by the counterparty to the contracts. Our exposure is diversified primarily among major investment grade financial institutions and we have master netting agreements with our counterparties that provide for offsetting payables against receivables from separate derivative contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. At March 31, 2023, our derivative counterparties include fourteen financial institutions, of which all but six are secured lenders in our bank credit facility. Counterparty credit risk is considered when determining the fair value of our derivative contracts. While our counterparties are primarily major investment grade financial institutions, the fair value of our derivative contracts has been adjusted to account for the risk of non-performance by certain of our counterparties, which was immaterial.
Interest Rate Risk
We are exposed to interest rate risk on our bank debt. We attempt to balance variable rate debt, fixed rate debt and debt maturities to manage interest costs, interest rate volatility and financing risk. This is accomplished through a mix of fixed rate senior and, at times, variable rate bank debt. At March 31, 2023, we had $1.9 billion of debt outstanding which bears interest at fixed rates averaging 5.9%. We had no variable rate bank debt outstanding as of March 31, 2023.
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