QEP RESOURCES, INC. Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company's operating results. MD&A should be read in conjunction with the financial statements and related Notes included in Part I, Item 1 of this Quarterly Report on Form 10-Q. The following information updates the discussion of QEP's financial condition provided in its Annual Report on Form 10-K for the year endedDecember 31, 2019 (2019 Form 10-K) and analyzes the changes in the results of operations between the three and six months endedJune 30, 2020 and 2019. For definitions of commonly used oil and gas terms found in this Quarterly Report on Form 10-Q, please refer to the "Glossary of Terms" provided in the 2019 Form 10-K.
OVERVIEW
QEP Resources, Inc. is an independent crude oil and natural gas exploration and production company with operations in two regions ofthe United States : theSouthern Region (primarily inTexas ) and theNorthern Region (primarily inNorth Dakota ). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are toQEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporate headquarters are located inDenver, Colorado and shares of QEP's common stock trade on theNew York Stock Exchange (NYSE) under the ticker symbol "QEP".
As a result of the reduction of the Company's operational footprint in 2019 following the Board's comprehensive review of strategic alternatives and determination to move forward as an independent company, QEP reassessed its organizational needs and significantly reduced its general and administrative expense to ensure its cost structure is competitive with industry peers.
As a part of the strategic initiatives and reduction in general and
administrative expense, QEP has incurred costs associated with contractual
termination benefits, including severance, accelerated vesting of share-based
compensation and other expenses. Refer to Note 3 - Acquisitions and Divestitures
and Note 9 - Restructuring in Part 1, Item I of this Quarterly Report on Form
10-Q for more information.
The Company continues to focus on reducing its operating costs, per well
drilling costs, general and administrative costs and managing its liquidity. We
believe our plan to generate Free Cash Flow (FCF) (a non-GAAP financial measure
defined and reconciled below) on an annual basis will allow us to further
strengthen our balance sheet and continue returning capital to shareholders.
26
--------------------------------------------------------------------------------Financial and Operating Highlights
During the three months ended
•Generated a net loss of$184.4 million , or$0.76 per diluted share; •Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of$157.3 million ; •Reported oil and condensate production of 3.9 MMbbls in thePermian Basin , an increase of 18% compared to the second quarter of 2019; •Lowered lease operating expense by 37% compared to the second quarter of 2019; •Reduced general and administrative expenses by 17% compared to the second quarter of 2019; •Amended the credit agreement, increasing liquidity by more than$500.0 million ; and •Repurchased a principal amount of$57.0 million of senior notes, due in 2021 and recorded a$2.1 million gain on early extinguishment of debt.
During the six months ended
•Generated net income of$183.0 million , or$0.76 per diluted share; •Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of$331.2 million ; •Reported cash provided by operating activities of$224.4 million ; •Reported Free Cash Flow (a non-GAAP measure defined and reconciled below) of$63.7 million ; •Reported oil and condensate production of 7.2 MMbbls in thePermian Basin , an increase of 16% compared to the first half of 2019; •Lowered lease operating expense by 29% compared to the first half of 2019; •Reduced general and administrative expenses by 55% compared to the first half of 2019; •Recognized an additional$128.1 million in accelerated alternative minimum tax (AMT) credit refunds from the CARES Act, resulting in an aggregate income tax receivable of$165.0 million as ofJune 30, 2020 ; and •Repurchased a principal amount of$155.2 million of senior notes, due in 2021, 2022 and 2023, and recorded a$27.5 million gain on early extinguishment of debt.
Outlook
The novel coronavirus disease (COVID-19) has created unprecedented challenges for our industry, customers and employees. The Company continues to take action to protect the core of its business and to ensure the health and safety of its employees, business partners and communities. Starting inMarch 2020 , the Company instituted various measures, including remote working and business travel restrictions, and we remain engaged with our business and community partners on how we can assist them during this time. The Company continues to evaluate additional safeguards and has implemented new procedures and policies to help protect the health and safety of the portion of the workforce whose jobs cannot be completed from home, including those who run our field operations. We continue to monitor the guidelines and recommendations provided by the relevant authorities, and we will continue to ensure we are doing our part in preventing the spread of the virus. As a result of lower demand caused by the COVID-19 pandemic and resulting oversupply of crude oil, the future prices of crude oil continue to be at low levels. In light of market conditions, during the first half of 2020 the Company took significant steps to proactively manage its cash flow and preserve liquidity by suspending completion operations and releasing two drilling rigs in thePermian Basin . In theWilliston Basin , we have completed all operated development activity for the year. These actions have reduced the Company's capital spending forecast for 2020 by 37% compared to our original 2020 guidance. While these decisions will result in lower 2020 oil production than originally forecasted, the Company believes that it will be able to maintain positive cash flow and protect its balance sheet, with the ultimate goal of protecting shareholder returns over the long term. Although the Company has already significantly reduced activity, we are prepared to reduce activity further for an extended period if necessary. The Company has utilized the slowdown to improve on its best in class operations and will continue to reduce expenses to the lowest and most efficient cost structure possible. Due to the Company's derivative positions and reduction in capital expenditures, the Company expects to generate FCF in 2020 despite the current market conditions. In addition to generating FCF, the Company anticipates receiving alternative minimum tax (AMT) credit refunds of$165.6 million in the next 12 months due to changes enacted by the CARES Act. The Company expects that the generation of FCF, cash on hand, anticipated AMT credit refunds and, as needed, borrowings made under its revolving credit facility, will be sufficient to meet its liquidity needs for the next 12 months, including its debt maturity inMarch 2021 . 27 -------------------------------------------------------------------------------- The Company believes that the overall reduction of global spending on new development projects, especially in theU.S. , will cause a reduction in the global oil supply, and that the eventual recovery from the COVID-19 pandemic will cause demand to be more in line with previously anticipated levels and, consequently, cause oil prices to recover. As a result of the actions taken, and continuing to be taken, and the expected stabilization of the global economy, the Company expects to emerge in a stronger position. Based on current commodity prices, we expect to be able to fund our planned capital program for 2020 with cash on hand and cash flow from operating activities. The mid-point of our total capital expenditures (excluding property acquisitions) for 2020 is expected to be approximately$360.0 million , a decrease of over 37% from both our 2019 capital expenditures and our original 2020 guidance. We continuously evaluate our level of drilling and completion activity in light of commodity prices, drilling results and changes in our operating and development costs and will adjust our capital investment program based on such evaluations. See "Cash Flow from Investing Activities" for further discussion of our capital expenditures.
Factors Affecting Results of Operations
Supply, Demand, Market Risk and their Impact on Oil Prices In the second quarter of 2020 the average price of WTI crude oil dropped 33% from the second quarter of 2019. Crude oil prices were negatively impacted by a variety of factors affecting current and expected supply and demand dynamics, including: the COVID-19 pandemic and related shut-down of various sectors of the global economy, which has resulted in a significant reduction in demand for crude oil, continuedU.S. supply growth driven by advances in drilling and completion technologies, and the delay of an agreement in early 2020 on production levels by members of theOrganization of Petroleum Exporting Countries (OPEC) and other oil producing countries, resulting in increased supply in the global market. Other factors impacting the supply and demand of our products include weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of theU.S. dollar as well as other factors, the majority of which are outside of our control. WhileOPEC and other oil producing countries have reduced production levels, andU.S. production has declined, a significant crude oil price recovery is not expected until global supply matches current lower levels of demand caused by the factors mentioned above, including the COVID-19 pandemic. Changes in the market prices for oil directly impact many aspects of QEP's business, including its financial condition, revenues, results of operations, planned drilling and completion activity and related capital expenditures, its proved undeveloped (PUD) reserves conversion rate, liquidity, rate of growth, costs of goods and services required to drill, complete and operate wells, and the carrying value of its oil and gas properties. The decline in the price of crude oil negatively impacted our oil revenue during the second quarter of 2020 but the value of our realized oil derivatives portfolio increased significantly, helping to offset the negative impact. Additionally, the volatility in commodity prices has impacted the Company's stock price and the fair value of the Company's debt securities, all of which impact our financial and operating results. Due to the changes in our drilling plans, we expect that our 2020 PUD conversion rate will be lower than originally anticipated; however, our total PUD reserves currently remain unchanged. Our future drilling plans, including our level of expenditures for the development of our oil reserves, total PUD reserves, operations and financial condition may be materially and adversely affected by declines in future oil prices. QEP's producing properties are primarily located in the Permian andWilliston basins. As a result of our lack of diversification in asset type and limited geographic diversification, any delays or interruptions of production caused by factors such as governmental regulation, transportation capacity constraints, curtailment of production or interruption of transportation, price fluctuations, natural disasters or shutdowns of the pipelines, connecting our production to refineries, including the potential shutdown of the Dakota Access Pipeline, would have a significantly greater impact on our results of operations than if we possessed more diverse assets and locations. 28 -------------------------------------------------------------------------------- Global Geopolitical and Macroeconomic Factors QEP continues to monitor the global economy, including global economic issues impacted by COVID-19; political unrest; oil producing countries' oil production and policies regarding production quotas; actions taken by theUnited States Congress and the President ofthe United States ; theU.S. federal budget deficit; changes in regulatory oversight policy; the impact of regulations and public and financial market sentiment regarding environmental, social and governance matters; commodity price volatility; tariffs on goods we use in our operations or on the products we sell; the impact of a potential increase in interest rates; volatility in various global currencies; and other factors. A dramatic decline in regional or global economic conditions, a major recession or depression, regional political instability, economic sanctions, war, or other factors beyond the control of QEP have had, and could continue to have, a significant impact on short-term and long-term oil and condensate, gas and NGL supply, demand and prices and the Company's ability to continue its planned drilling programs which could materially impact the Company's financial position, results of operations and cash flow from operations. Disruption to the global oil supply system, political and/or economic instability, fluctuations in currency values, and/or other factors could trigger additional volatility in oil prices. Due to continued global economic uncertainty and the corresponding volatility of commodity prices, QEP continues to focus on maintaining a sufficient liquidity position to ensure financial flexibility. QEP uses commodity derivatives to reduce the volatility of the prices QEP receives for a portion of its production and to partially protect cash flow and returns on invested capital from a drop in commodity prices. Generally, QEP intends to enter into commodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. Gains on settled derivatives offset a large portion of the impact of the recent decline in oil prices on our oil revenues. There can be no assurances that we will be able to add derivative positions to cover the balance of our forecasted production for 2021 at favorable prices. See Part 1, Item 3 - "Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk Management" for further details on QEP's commodity derivatives transactions. Potential for Future Asset Impairments The carrying values of the Company's properties are sensitive to declines in oil, gas and NGL prices as well as increases in various development and operating costs and expenses and, therefore, are at risk of impairment. The Company uses a cash flow model to assess its proved oil and gas properties and operating lease right-of-use assets for impairment. The cash flow model includes numerous assumptions, including estimates of future oil and condensate, gas and NGL production, estimates of future prices for production that are based on the price forecast that management uses to make investment decisions, including estimates of basis differentials, future operating costs, transportation expenses, production taxes, and development costs that management believes are consistent with its price forecast, and discount rates. Management also considers a number of other factors, including the forward curve for future oil and gas prices, and developments in regional transportation infrastructure when developing its estimate of future prices for production. All inputs for the cash flow model are evaluated at each date of estimate. We base our estimates on projected financial information that we believe to be reasonably likely to occur. An assessment of the sensitivity of our capitalized costs to changes in the assumptions in our cash flow calculations is not practicable, given the numerous assumptions (e.g., future oil, gas and NGL prices; production and reserves; pace and timing of development drilling plans; timing of capital expenditures; operating costs; drilling and development costs; and inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced oil, gas and NGL prices on future undiscounted cash flows would likely be offset by lower drilling and development costs and lower operating costs. The signing of a purchase and sale agreement could also cause the Company to recognize an impairment of proved properties. For assets subject to a purchase and sale agreement, the terms of the purchase and sale agreement are used as an indicator of fair value.
During the six months ended
We could be at risk for proved and unproved property and operating lease right-of-use asset impairments if current market conditions persist for an extended period of time, we experience negative changes in estimated reserve quantities or the forward oil prices decline fromJune 30, 2020 levels. The actual amount of impairment incurred, if any, for oil and gas properties will depend on a variety of factors including, but not limited to: subsequent forward price curve changes, the additional risk-adjusted value of probable and possible reserves associated with our properties, weighted-average cost of capital, operating cost estimates and future capital expenditure estimates. 29 -------------------------------------------------------------------------------- Income Tax The tax legislation enacted inDecember 2017 reduced our federal corporate tax rate from 35% to 21%. In addition, the tax legislation eliminated the corporate Alternative Minimum Tax (AMT), allowing the Company to claim AMT refunds for AMT credits carried forward from prior tax years. The Company received$73.9 million of AMT credit refunds in 2019. The CARES Act enacted inMarch 2020 permitted the Company to carry back its net operating loss (NOL) generated in 2018, creating additional AMT credits, and accelerate all of its AMT credit refunds. The Company now anticipates that after carrybacks it will receive$165.6 million of AMT credit refunds which are included in "Income tax receivable" on the balance sheets as ofJune 30, 2020 . Acquisitions and Divestitures QEP's strategy is to generate FCF, and it believes its inventory of identified drilling locations provides a solid base to achieve this strategy, but it will continue to evaluate and potentially acquire properties in its operating areas to add additional development opportunities and facilitate the drilling of long lateral wells. Acquisitions During the six months endedJune 30, 2020 and 2019, QEP acquired various oil and gas properties, which primarily included proved acreage in thePermian Basin for an aggregate purchase price of$4.1 million and$1.8 million , respectively, subject to post-closing purchase price adjustments.
Divestitures
During the six months endedJune 30, 2020 , QEP received net cash proceeds of$12.9 million and recorded a net pre-tax gain on sale of$3.7 million , primarily related to the divestiture of properties outside its main operating areas. InJanuary 2019 , QEP sold itsHaynesville/Cotton Valley assets (Haynesville Divestiture) and during the year endedDecember 31, 2019 , reached final settlement on asserted environmental and title defects and received aggregate net cash proceeds of$633.9 million . QEP recorded a total net pre-tax loss, including restructuring costs, of$4.0 million . During the three and six months endedJune 30, 2019 , QEP recorded$14.3 million of pre-tax gain on sale and$0.7 million of pre-tax loss on sale, respectively, within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the statements of operations. Refer to Note 3 - Acquisitions and Divestitures in Part 1, Item I of this Quarterly Report on Form 10-Q for more information. In addition to the Haynesville Divestiture, during the six months endedJune 30, 2019 , QEP recorded net cash proceeds of$39.6 million and recorded a net pre-tax gain on sale of$5.3 million related to the divestiture of properties outside our main operating areas. Multi-Well Pad Drilling and Completion To reduce the costs of well location construction and rig mobilization and demobilization and to obtain other efficiencies, QEP utilizes multi-well pad drilling, where practical. For example, in thePermian Basin , QEP utilizes "tank-style" development, in which we simultaneously develop multiple subsurface targets by drilling and completing all wells in a given "tank" before any individual well is turned to production. We believe this approach maximizes the economic recovery of oil and condensate through the simultaneous development of multiple subsurface targets, while improving capital efficiency though shared surface facilities, which we believe will reduce per-unit operating costs and result in expanded operating margins and improve our returns on invested capital. Because wells drilled on a pad are not completed and brought into production until all wells on the pad are drilled and the drilling rig is moved from the location, multi-well pad drilling delays the completion of wells, the commencement of production from new wells, and may negatively affect production from existing offset wells. In addition, existing wells that offset new wells being completed by QEP or offset operators may need to be temporarily shut-in during the completion process. Such delays and well shut-ins have caused and may continue to cause volatility in QEP's quarterly operating results. In addition, delays in completion of wells may impact the timing of planned conversions of PUD reserves to proved developed reserves. Uncertainties Related to Claims QEP is currently subject to claims that could adversely impact QEP's liquidity, operating results and capital expenditures for a particular reporting period, including, but not limited to those described in Note 11 - Commitments and Contingencies, in Item 1 of Part I of this Quarterly Report on Form 10-Q. Given the uncertainties involved in these matters, QEP is unable to predict the ultimate outcomes. 30 -------------------------------------------------------------------------------- Critical Accounting Estimates QEP's significant accounting policies are described in Item 7 of Part II of its 2019 Form 10-K. The Company's financial statements are prepared in accordance with GAAP. The preparation of the Company's financial statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. QEP's accounting policies on oil and gas reserves, successful efforts accounting for oil and gas operations, impairment of long-lived assets and income taxes, among others, may involve a high degree of complexity and judgment on the part of management. Further, these estimates and other factors, including those outside of the Company's control, such as the impact of sustained lower commodity prices, could have a significant adverse impact to the Company's financial condition, results of operations and cash flows. Drilling, Completion and Production Activities The following table presents operated and non-operated wells in the process of being drilled or waiting on completion as ofJune 30, 2020 : Operated Non-operated Drilling Drilling Waiting on completion Drilling Waiting on completion Rigs Gross Net Gross Net Gross Net Gross Net Northern Region Williston Basin - - - 6 4.4 - - 21 3.4 Southern Region Permian Basin(1) 1 9 7.8 37 33.9 - - 4 0.4
____________________________
(1)Eight of the nine gross operated wells in the
Delays in completion of wells could impact planned conversions of PUD reserves to proved developed reserves and volatility in QEP's quarterly operating results. QEP had 43 gross operated wells waiting on completion as ofJune 30, 2020 . The following table presents the number of operated wells in the process of being drilled or waiting on completion atJune 30, 2020 and operated wells completed and turned to sales (put on production) for the six months endedJune 30, 2020 : Permian Basin Williston Basin As of June 30, 2020 Gross Net Gross Net Well Progress Drilling 9 7.8 - - Waiting to be completed 37 33.9 4 2.9 Undergoing completion - - 2 1.5 Waiting on completion 37 33.9 6 4.4 Put on production 36 34.4 - - 31
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The following table presents the number of operated and non-operated wells
completed and turned to sales (put on production) for the three and six months
ended
Operated Put on Production Non-operated Put on Production
Three Months Ended Six Months Ended Three Months Ended Six Months Ended
June 30, 2020 June 30, 2020 June 30, 2020 June 30, 2020
Gross Net Gross Net Gross Net Gross Net (1)
Northern Region
Williston Basin - - - - - - 5 -
Southern Region
Permian Basin 11 9.5 36 34.4 - - - -
_______________________
(1) Net working interest related to the 5 gross non-operated wells in the
RESULTS OF OPERATIONS
Net Income
QEP generated a net loss during the second quarter of 2020 of$184.4 million , or$0.76 per diluted share, compared to a net income of$48.8 million , or$0.20 per diluted share, in the second quarter of 2019. The$233.2 million decrease in net income in the second quarter of 2020 compared to 2019 was primarily due to a$273.6 million increase in unrealized derivative losses, partially offset by an$83.3 million increase in income tax benefit. During the first half of 2020, QEP generated net income of$183.0 million , or$0.76 per diluted share, compared to a net loss of$67.9 million or$0.29 per diluted share, in the first half of 2019. The$250.9 million increase in net income in the first half of 2020 compared to 2019 was primarily due to a$309.5 million increase in unrealized derivative gains, partially offset by an$95.0 million increase in income tax expense.
See below for additional discussion regarding the components of net income (loss) for each of the periods presented.
Adjusted EBITDA (Non-GAAP)
Management defines Adjusted EBITDA (a non-GAAP measure) as earnings before
interest, income taxes, depreciation,
depletion and amortization (EBITDA), adjusted to exclude changes in fair value
of derivative contracts, exploration expenses,
gains and losses from asset sales, impairment, gains or losses from early
extinguishment of debt and certain other items. Management uses Adjusted EBITDA
to evaluate QEP's financial performance and trends, make operating decisions and
allocate resources. Management believes the measure is useful supplemental
information for investors because it eliminates the impact of certain
nonrecurring, non-cash and/or other items that management does not consider as
indicative of QEP's performance from period to period. QEP's Adjusted EBITDA may
be determined or calculated differently than similarly titled measures of other
companies in our industry, which could reduce the usefulness of this non-GAAP
financial measure when comparing our performance to that of other companies.
32
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Below is a reconciliation of net income (loss) (the most comparable GAAP
measure) to Adjusted EBITDA. This non-GAAP measure should be considered by the
reader in addition to, but not instead of, the financial statements prepared in
accordance with GAAP.
Six Months Ended June
Three Months Ended June 30, 30,
2020 2019 2020 2019
(in millions)
Net income (loss) $ (184.4) $ 48.8 $ 183.0 $ (67.9)
Interest expense 29.8 33.2 61.4 67.2
Interest and other (income) expense (2.6) (0.9) - (3.7)
Income tax provision (benefit) (53.6) 29.7 12.7 (82.3)
Depreciation, depletion and amortization 149.4 128.0 291.6 251.3
Unrealized (gains) losses on derivative
contracts 219.1 (54.5) (188.2) 121.3
Gain from early extinguishment of debt (0.4) - (25.6) -
Net (gain) loss from asset sales, inclusive of
restructuring costs - (17.8) (3.7) (4.6)
Impairment - - - 5.0
Adjusted EBITDA $ 157.3 $ 166.5 $ 331.2 $ 286.3
In the second quarter of 2020, Adjusted EBITDA decreased to $157.3 million
compared to $166.5 million in the second quarter of 2019, primarily due to a
$176.3 million decrease in oil, gas, and NGL sales, which was primarily due to a
59% decrease in average field-level prices, partially offset by a $136.4 million
increase in realized derivative gains, a $16.9 million reduction in lease
operating expenses and a $14.0 million decrease in production and property
taxes.
In the first half of 2020, Adjusted EBITDA increased to $331.2 million compared
to $286.3 million in the first half of 2019, primarily due to a $184.9 million
increase in realized derivative gains, a $52.6 million decrease in general and
administrative expenses and a $28.2 million decrease in lease operating costs,
partially offset by a $230.1 million decrease in oil, gas and NGL sales,
primarily due to a 40% decrease in average field-level prices.
Free Cash Flow (Non-GAAP)
Management defines Free Cash Flow as Adjusted EBITDA plus non-cash share-based
compensation less interest expense, excluding amortization of debt issuance
costs and discounts, and accrued property, plant and equipment capital
expenditures. Management believes that this measure is useful to management and
investors for analysis of the Company's ability to repay debt, fund acquisitions
or repurchase stock.
33
--------------------------------------------------------------------------------Below is a reconciliation of Net Cash Provided by (Used in) Operating Activities (the most comparable GAAP measure) to Free Cash Flow. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP.
Six Months Ended
June 30,
2020 2019
(in millions)
Cash Flow Information:
Net Cash Provided by (Used in) Operating Activities $ 224.4 $ 195.7
Net Cash Provided by (Used in) Investing Activities (237.0) 348.1
Net Cash Provided by (Used in) Financing Activities (149.6) (445.6)
Free Cash Flow
Net Cash Provided by (Used in) Operating Activities $ 224.4 $ 195.7
Amortization of debt issuance costs and discounts (2.6) (2.7)
Interest expense 61.4 67.2
Unrealized (gains) losses on marketable securities - 2.7
Interest and other income (expense) - (3.7)
Deferred income taxes (benefit) (141.4) 87.7
Income tax (provision) benefit 12.7 (82.3)
Non-cash share-based compensation (6.4) (11.2)
Changes in operating assets and liabilities 183.1 32.9
Adjusted EBITDA $ 331.2 $ 286.3
Non-cash share-based compensation 6.4 11.2
Interest expense, excluding amortization of debt
issuance costs and discounts (58.8) (64.5)
Accrued property, plant and equipment capital
expenditures (215.1) (337.1)
Free Cash Flow $ 63.7 $ (104.1)
In the first half of 2020, the Company generated FCF of $63.7 million compared
to an outspend of $104.1 million in the first half of 2019, primarily due to an
$122.0 million decrease in accrued property, plant and equipment capital
expenditures and a $44.9 million increase in Adjusted EBITDA.
34
--------------------------------------------------------------------------------Revenue
The following table presents our revenues disaggregated by revenue source.
Three Months Ended Six Months Ended
June 30, June 30,
2020 2019 Change 2020 2019 Change
(in millions)
Oil and condensate, gas and NGL sales,
as presented $ 118.3 $ 294.6
15.3 12.7 2.6 29.6 26.5 3.1
Oil and condensate, gas and NGL sales,
as adjusted(2) 133.6 $ 307.3 $ (173.7) $ 369.7 $ 596.7 $ (227.0)
Oil and condensate sales $ 118.5 $ 285.7 $ (167.2) $ 338.5 $ 535.2 $ (196.7)
Gas sales 8.8 7.3 1.5 15.3 30.3 (15.0)
NGL sales 6.3 14.3 (8.0) 15.9 31.2 (15.3)
Oil and condensate, gas and NGL sales,
as adjusted(2) $ 133.6 307.3 $ (173.7) $ 369.7 $ 596.7 $ (227.0)
____________________________
(1)Depending on the terms of the contract, a portion of the total transportation
and processing costs incurred by the Company are deducted from revenue. Refer to
the Operating Expenses section below for a reconciliation of total
transportation and processing costs.
(2)Oil and condensate, gas and NGL sales (the most comparable GAAP measure) as
presented on the statements of operations is reconciled to oil and condensate,
gas and NGL sales, as adjusted (a non-GAAP measure). Management excludes costs
deducted from revenue to reflect total revenue associated with its production
prior to deducting any expenses. Management believes that this non-GAAP measure
is useful supplemental information for investors as it is reflective of the
total revenue generated from its wells for the period. This non-GAAP measure
should be considered by the reader in addition to, but not instead of, the
financial measure prepared in accordance with GAAP. Refer to Note 2 - Revenue in
Part 1, Item I of this Quarterly Report on Form 10-Q.
Revenue, Volume and Price Variance Analysis
The following table shows volume and price related changes for each of QEP's adjusted production-related revenue categories for the three and six months endedJune 30, 2020 , compared to the three and six months endedJune 30, 2019 : Oil and condensate Gas NGL Total (in millions) Oil and condensate, gas and NGL sales, as adjusted Three months ended June 30, 2019$ 285.7 $ 7.3 $ 14.3 $ 307.3 Changes associated with volumes(1) 17.0 0.9 (0.3) 17.6 Changes associated with prices(2) (184.2) 0.6 (7.7) (191.3) Three months ended June, 2020$ 118.5 $ 8.8
Oil and condensate, gas and NGL sales, as adjusted Six months ended June 30, 2019$ 535.2 $ 30.3 $ 31.2 $ 596.7 Changes associated with volumes(1) 23.3 (0.6) 2.1 24.8 Changes associated with prices(2) (220.0) (14.4) (17.4) (251.8) Six months ended June, 2020$ 338.5 $ 15.3
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35
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(1)The revenue variance attributed to the change in volume is calculated by
multiplying the change in volume from the three and six months ended
Production and Pricing
Three Months Ended June 30, Six Months Ended June 30,
2020 2019 Change 2020 2019 Change
Total production volumes (Mboe)
Northern Region
Williston Basin 2,515.0 2,962.4 (447.4) 5,493.1 6,339.4 (846.3)
Other Northern 4.4 21.0 (16.6) 7.0 45.7 (38.7)
Southern Region
Permian Basin 5,453.2 4,552.4 900.8 10,399.9 8,634.7 1,765.2
Haynesville/Cotton Valley - (6.3) 6.3 - 310.9 (310.9)
Other Southern 0.3 5.2 (4.9) 3.8 10.3 (6.5)
Total production 7,972.9 7,534.7 438.2 15,903.8 15,341.0 562.8
Total equivalent prices (per Boe)
Average field-level equivalent price
15.10 (2.13) 17.23 10.25 (1.43) 11.68
Net realized equivalent price
36
--------------------------------------------------------------------------------Oil and Condensate Volumes and Prices
Three Months Ended June 30, Six Months Ended June 30,
2020 2019 Change 2020 2019 Change
Oil and condensate production
volumes (Mbbl)
Northern Region
Williston Basin 1,600.6 1,861.4 (260.8) 3,506.3 4,019.4 (513.1)
Other Northern 1.1 13.0 (11.9) (2.1) 24.0 (26.1)
Southern Region
Permian Basin 3,856.8 3,273.9 582.9 7,173.1 6,188.4 984.7
Other Southern - 2.0 (2.0) 0.3 2.1 (1.8)
Total production 5,458.5 5,150.3 308.2 10,677.6 10,233.9 443.7
Average field-level oil prices (per
bbl)
Northern Region $ 22.15 $ 57.60 $ (35.45) $ 32.74 $ 54.00 $ (21.26)
Southern Region $ 21.54 $ 54.24 $ (32.70) $ 31.20 $ 51.18 $ (19.98)
Average field-level price $ 21.72 $ 55.46 $ (33.74) $ 31.70 $ 52.30 $ (20.60)
Commodity derivative impact 22.01 (3.11) 25.12 15.24 (1.85) 17.09
Net realized price $ 43.73 $ 52.35 $ (8.62) $ 46.94 $ 50.45 $ (3.51)
Oil and condensate revenues decreased $167.2 million , or 59%, in the second
quarter of 2020 compared to the second quarter of 2019, due to lower average
field-level prices, partially offset by higher aggregate oil and condensate
production volumes. Average field-level oil prices decreased 61% in the second
quarter of 2020 compared to the second quarter of 2019, primarily driven by a
decrease in average NYMEX-WTI oil prices and a $1.85 per bbl, or 42%, increase
in the basis differential relative to the average NYMEX-WTI oil price for the
comparable periods. The net realized price for the second quarter of 2020 was
$43.73 per barrel, which included a $22.01 per barrel positive impact from our
settled derivative contracts. The net realized price was 16% lower than the
$52.35 per barrel in the second quarter of 2019 due to the significant decline
in the average field-level price. The 6% increase in production volumes was
primarily driven by an increase in production in the Permian Basin due to
continued drilling and completion activity in the second quarter of 2020 and
improved well performance attributable to well completion design, partially
offset by a decrease in production in the Williston Basin due to a reduced level
of activity.
Oil and condensate revenues decreased $196.7 million , or 37%, in the first half
of 2020 compared to the first half of 2019, due to lower average field-level
prices, partially offset by higher aggregate oil and condensate production
volumes. Average field-level oil prices decreased 39% in the first half of 2020
compared to the first half of 2019, primarily driven by a decrease in average
NYMEX-WTI oil prices, partially offset by a $0.23 per bbl, or 5%, decrease in
the basis differential relative to the average NYMEX-WTI oil price for the
comparable periods. The net realized price for the first half of 2020 was $46.94
per barrel, which included a $15.24 per barrel positive impact from our settled
derivative contracts. The net realized price was 7% lower than the $50.45 per
barrel in the first half of 2019 due to the significant decline in the average
field-level price. The 4% increase in production volumes was primarily driven by
an increase in production in the Permian Basin due to continued drilling and
completion activity in the first half of 2020, partially offset by a decrease in
production in the Williston Basin due to a reduced level of activity.
37
--------------------------------------------------------------------------------
Gas Volumes and Prices
Three Months Ended June 30, Six Months Ended June 30,
2020 2019 Change 2020 2019 Change
Gas production volumes (Bcf)
Northern Region
Williston Basin 2.7 3.5 (0.8) 5.7 7.3 (1.6)
Other Northern 0.1 - 0.1 0.1 0.1 -
Southern Region
Permian Basin 5.3 3.7 1.6 10.4 7.1 3.3
Haynesville/Cotton Valley - - - - 1.9 (1.9)
Other Southern - - - - - -
Total production 8.1 7.2 0.9 16.2 16.4 (0.2)
Average field-level gas prices (per
Mcf)
Northern Region $ 1.44 $ 2.15 $ (0.71) $ 1.52 $ 2.72 $ (1.20)
Southern Region $ 0.89 $ (0.06) $ 0.95 $ 0.63 $ 1.12 $ (0.49)
Average field-level price $ 1.08 $ 1.01
0.03 - 0.03 0.01 (0.18) 0.19
Net realized price $ 1.11 $ 1.01 During the second quarter of 2020, the Company elected to reject ethane in thePermian Basin . Gas revenues increased$1.5 million , or 21%, in the second quarter of 2020 compared to the second quarter of 2019, due to higher gas production volumes and higher average field-level prices. Production volumes increased 13% in the second quarter of 2020 compared to the second quarter of 2019, primarily in thePermian Basin due to continued drilling and completion activity and the decreased amount of ethane recovered as NGL. This production increase was partially offset by a decrease in production in theWilliston Basin due to a reduced level of activity in the second quarter of 2020. Average field-level gas prices increased 7% in the second quarter of 2020 compared to the second quarter of 2019, primarily driven by a$0.99 per Mcf, or 61%, decrease in regional basis differentials, partially offset by a decrease in average NYMEX-HH gas spot prices in comparable periods. Gas revenues decreased$15.0 million , or 50%, in the first half of 2020 compared to the first half of 2019, due to lower average field-level prices and lower gas production volumes. Average field-level gas prices decreased 48% in the first half of 2020 compared to the first half of 2019, primarily driven by a decrease in average NYMEX-HH gas spot prices, partially offset by a$0.17 per Mcf, or 16%, decrease in regional basis differentials relative to the average NYMEX-HH gas price in comparable periods. Production volumes decreased 1% in the first half of 2020 compared to the first half of 2019, primarily due to the Haynesville Divestiture and a reduced level of activity in theWilliston Basin . These production decreases were partially offset by increased production in thePermian Basin due to continued drilling and completion activity and the decreased amount of ethane recovered as NGL in the first half of 2020. 38 --------------------------------------------------------------------------------
NGL Volumes and Prices
Three Months Ended June 30, Six Months Ended June 30,
2020 2019 Change 2020 2019 Change
NGL production volumes (Mbbl)
Northern Region
Williston Basin 449.7 526.6 (76.9) 1,035.1 1,105.4 (70.3)
Other Northern (0.1) 0.7 (0.8) 0.5 0.4 0.1
Southern Region
Permian Basin 714.9 658.6 56.3 1,497.7 1,258.5 239.2
Other Southern 0.1 0.1 - 0.4 0.5 (0.1)
Total production 1,164.6 1,186.0 (21.4) 2,533.7 2,364.8 168.9
Average field-level NGL prices
(per bbl)
Northern Region $ 0.97 $ 10.96 $ (9.99) $ 3.83 $ 11.91 $ (8.08)
Southern Region $ 8.25 $ 12.94 $ (4.69) $ 8.00 $ 14.30 $ (6.30)
Average field-level price $ 5.44 $ 12.06
- - - - - -
Net realized price $ 5.44 $ 12.06 $ (6.62) $ 6.30 $ 13.18 $ (6.88)
During the second quarter of 2020, the Company elected to reject ethane in the
Permian Basin . NGL revenues decreased $8.0 million , or 56%, during the second
quarter of 2020 compared to the second quarter of 2019, due to lower average
field-level prices and lower NGL production volumes. The 55% decrease in NGL
prices during the second quarter of 2020 compared to the second quarter of 2019
was primarily driven by a decrease in propane, ethane and other NGL component
prices. The 2% decrease in NGL production volumes was primarily driven by
decreased activity in the Williston Basin and a decreased amount of the ethane
recovered in the Permian Basin , partially offset by continued drilling and
completion activity in the Permian Basin .
NGL revenues decreased $15.3 million , or 49%, during the first half of 2020
compared to the first half of 2019, due to lower average field-level prices,
partially offset by higher NGL production volumes. The 52% decrease in NGL
prices during the first half of 2020 compared to the first half of 2019 was
primarily driven by a decrease in propane, ethane and other NGL component
prices. The 7% increase in NGL production volumes was primarily driven by
continued drilling and completion activity in the Permian Basin and an increased
amount of ethane recovered in the Williston Basin ; partially offset by decreased
activity in the Williston Basin and a decreased amount of ethane recovered in
the Permian Basin starting in April 2020 .
39
--------------------------------------------------------------------------------Operating Expenses
The following table presents QEP production costs and production costs on a per
unit of production basis:
Three Months Ended June 30, Six Months Ended June 30,
2020 2019 Change 2020 2019 Change
(in millions)
Lease operating expense $ 28.8 $ 45.7 $ (16.9) $ 69.0 $ 97.2 $ (28.2)
Adjusted transportation and
processing costs(1) 27.6 22.6 5.0 55.4 47.3 8.1
Production and property taxes 9.6 23.6 (14.0) 28.3 47.6 (19.3)
Total production costs $ 66.0 $ 91.9 $ (25.9) $ 152.7 $ 192.1 $ (39.4)
(per Boe)
Lease operating expense $ 3.62 $ 6.06 $ (2.44) $ 4.34 $ 6.34 $ (2.00)
Adjusted transportation and
processing costs(1) 3.47 3.00 0.47 3.48 3.09 0.39
Production and property taxes 1.21 3.13 (1.92) 1.78 3.10 (1.32)
Total production costs $ 8.30 $ 12.19 $ (3.89) $ 9.60 $ 12.53 $ (2.93)
____________________________
(1)Below are reconciliations of transportation and processing costs (the most
comparable GAAP measure) as presented on the statements of operations and on a
unit of production basis to adjusted transportation and processing costs.
Adjusted transportation and processing costs includes transportation and
processing costs that are reflected as part of "Oil and condensate, gas and NGL
sales" on the statements of operations. Management adds these costs together to
reflect the total operating costs associated with its production. Management
believes that this non-GAAP measure is useful supplemental information for
investors as it is reflective of the total production costs required to operate
the wells for the period. This non-GAAP measure should be considered by the
reader in addition to, but not instead of, the financial measure prepared in
accordance with GAAP. Refer to Note 2 - Revenue in Part 1, Item I of this
Quarterly Report on Form 10-Q.
Three Months Ended June 30, Six Months Ended June 30,
2020 2019 Change 2020 2019 Change
(in millions)
Transportation and processing
costs, as presented $ 12.3 $ 9.9 $ 2.4 $ 25.8 $ 20.8 $ 5.0
Transportation and processing costs
deducted from oil and condensate,
gas and NGL sales 15.3 12.7 2.6 29.6 26.5 3.1
Adjusted transportation and
processing costs $ 27.6 $ 22.6 $ 5.0 $ 55.4 $ 47.3 $ 8.1
(per Boe)
Transportation and processing
costs, as presented $ 1.55 $ 1.31 $ 0.24 $ 1.62 $ 1.36 $ 0.26
Transportation and processing costs
deducted from oil and condensate,
gas and NGL sales 1.92 1.69 0.23 1.86 1.73 0.13
Adjusted transportation and
processing costs $ 3.47 $ 3.00 $ 0.47 $ 3.48 $ 3.09 $ 0.39
Lease operating expense (LOE). QEP's LOE decreased $16.9 million , or 37%, in the
second quarter of 2020 compared to the second quarter of 2019, primarily due to
a decrease in workover activity, water disposal expenses, maintenance and repair
expenses, and power and fuel expenses in the Williston and Permian basins as a
result of continuing efforts to reduce operating expenses.
During the second quarter of 2020, LOE decreased $2.44 per Boe, or 40%, compared
to the second quarter of 2019, primarily due to continuing efforts to reduce
operating expenses.
40
--------------------------------------------------------------------------------
QEP's LOE decreased
During the first half of 2020, LOE decreased$2.00 per Boe, or 32%, compared to the first half of 2019, primarily due to continuing efforts to reduce operating expenses. Adjusted transportation and processing costs (non-GAAP). Adjusted transportation and processing costs increased$5.0 million , or 22%, in the second quarter of 2020 compared to the second quarter of 2019. The increase in expense was primarily due to an increase in both production and gathering and processing rates in thePermian Basin and increased gathering and processing rates in theWilliston Basin , partially offset by decreased production in theWilliston Basin . During the second quarter of 2020, adjusted transportation and processing costs increased$0.47 per Boe, or 16%, compared to the second quarter of 2019. The increase was primarily due to increased gathering and processing rates in theWilliston and Permian basins. Adjusted transportation and processing costs increased$8.1 million , or 17%, in the first half of 2020 compared to the first half of 2019. The increase in expense was primarily due to increased production in thePermian Basin and increased gathering and processing rates in theWilliston Basin , partially offset by the Haynesville Divestiture and decreased production in theWilliston Basin .
During the first half of 2020, adjusted transportation and processing costs
increased
Production and property taxes. Production and property taxes decreased$14.0 million , or 59%, in the second quarter of 2020 compared to the second quarter of 2019, primarily due to decreased revenues in theWilliston and Permian basins and the related production taxes, combined with decreased property tax expense in thePermian Basin . During the second quarter of 2020, production and property taxes decreased$1.92 per Boe, or 61%, compared to the second quarter of 2019, primarily due to a decrease in revenues and the associated production taxes in theWilliston and Permian basins and lower property tax expense per Boe in thePermian Basin . Production and property taxes decreased$19.3 million , or 41%, in the first half of 2020 compared to the first half of 2019, primarily due to decreased revenues in theWilliston and Permian basins and the related production taxes, combined with decreased property tax expense in thePermian Basin . During the first half of 2020, production and property taxes decreased$1.32 per Boe, or 43%, compared to the first half of 2019, primarily due to a decrease in revenues and the associated production taxes in theWilliston and Permian basins and lower property tax expense per Boe in thePermian Basin . Depreciation, depletion and amortization (DD&A). DD&A expense increased$21.4 million in the second quarter of 2020 compared to the second quarter of 2019, primarily due to increased production in thePermian Basin and higher DD&A rates in the Permian andWilliston basins. The increases in DD&A expense were partially offset by a decrease in production in theWilliston Basin . DD&A expense increased$40.3 million in the first half of 2020 compared to the first half of 2019, primarily due to increased production in thePermian Basin and higher DD&A rates in the Permian andWilliston basins. The increases in DD&A expense were partially offset by a decrease in production in theWilliston Basin .
Impairment expense. During the second quarter of 2020 and 2019, there were no impairment charges.
During the first half of 2020, there were no impairment charges. During the
first half of 2019, QEP recorded impairment charges of
41
--------------------------------------------------------------------------------General and administrative (G&A) expense.
The following table presents detail about QEP's share-based compensation and
deferred compensation components of QEP's total general and administrative
expense, including the cash and non-cash components, for the three and six
months ended
Three Months Ended June 30, Six Months Ended June 30,
2020 2019 Change 2020 2019 Change
(in millions)
General and administrative
(excluding share-based compensation
and deferred compensation) $ 18.1 $ 26.0 $ (7.9) $ 38.3 $ 74.2 $ (35.9)
General and administrative
(share-based compensation and
deferred compensation):
Cash share-based compensation (1) 0.1 0.4 (0.3) 0.7 5.7 (5.0)
Non-cash share-based compensation
(1) 3.1 4.8 (1.7) 6.4 11.2 (4.8)
Deferred compensation mark-to-market
adjustments (2) 5.0 0.3 4.7 (3.2) 3.7 (6.9)
Total General and administrative $ 26.3 $ 31.5 ____________________________
(1)Cash share-based compensation represents restricted cash awards, performance share units and restricted share units recorded under the Company's Long-Term Incentive Plan and Cash Incentive Plan. Non-cash share-based compensation represents stock options and restricted share awards recorded under the Company's Long-Term Incentive Plan. Refer to Note 12 - Share-Based and Long-Term Incentive Compensation, in Item I of Part I of this Quarterly Report on Form 10-Q for more information on share-based compensation. (2)Deferred compensation mark-to-market adjustments represents mark-to-market adjustments of the Company's nonqualified, unfunded deferred compensation wrap plan (Wrap Plan). Refer to Note 1 - Basis of Presentation, in Item I of Part I of this Quarterly Report on Form 10-Q for more information on the Wrap Plan. During the second quarter of 2020, G&A expense decreased$5.2 million , or 17%, compared to the second quarter of 2019. During the second quarter of 2020 and 2019, QEP incurred$0.6 million and$7.2 million , respectively, in costs associated with the implementation of our strategic initiatives, of which$0.5 million and$6.0 million , respectively, related to restructuring costs (refer to Note 9 - Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q). Excluding costs associated with the implementation of our strategic initiatives, G&A expense increased by$1.5 million , or 6%, primarily due to a$4.7 million increase in expense related to the increase in market value on the deferred compensation plan, partially offset by a$3.2 million decrease in labor, benefits and bonus, primarily due to workforce reductions. During the first half of 2020, G&A expense decreased$52.6 million , or 55%, compared to the first half of 2019. During the first half of 2020 and 2019, QEP incurred$2.0 million and$33.2 million , respectively, in costs associated with the implementation of our strategic initiatives, of which$1.9 million and$26.3 million , respectively, related to restructuring costs (refer to Note 9 - Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q). Excluding costs associated with the implementation of our strategic initiatives, G&A expense decreased by$21.4 million , or 35%, primarily due to an$11.6 million decrease in labor, benefits and bonus, primarily due to workforce reductions, a$6.9 million decrease in expense related to the decrease in market value on the deferred compensation plan and a$2.3 million decrease in share-based compensation due to the reduction in workforce and the decline in QEP's stock price. Net gain (loss) from asset sales, inclusive of restructuring costs. During the second quarter of 2020, QEP recognized a gain on the sale of assets of less than$0.1 million , primarily related to divestitures of properties outside our main operating areas. During the second quarter of 2019, QEP recognized a gain on the sale of assets of$17.8 million , primarily related to a net pre-tax gain on sale of$14.3 million related to our Haynesville Divestiture. 42 -------------------------------------------------------------------------------- During the first half of 2020, QEP recognized a gain on the sale of assets of$3.7 million , primarily related to divestitures of properties outside our main operating areas. During the first half of 2019, QEP recognized a gain on the sale of assets of$4.6 million , primarily related to the$5.5 million gain from the divestiture of other properties, partially offset by a net pre-tax loss on sale of$0.7 million related to our Haynesville Divestiture, which included$4.3 million of restructuring costs (refer to Note 9 - Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q for more information).
Non-operating Expenses
Realized and unrealized gains (losses) on derivative contracts. Gains and losses on derivative contracts are comprised of both realized and unrealized gains and losses on QEP's commodity derivative contracts, which are marked-to-market each quarter. During the second quarter of 2020, losses on commodity derivative contracts were$98.7 million , of which$219.1 million were unrealized losses and$120.4 million were realized gains on settled derivative contracts. During the second quarter of 2019, gains on commodity derivative contracts were$38.5 million , of which$54.5 million were unrealized gains and$16.0 million were realized losses on settled derivative contracts. During the first half of 2020, gains on commodity derivative contracts were$351.2 million , of which$188.2 million were unrealized gains and$163.0 million were realized gains on settled derivative contracts. During the first half of 2019, losses on commodity derivative contracts were$143.2 million , of which$123.1 million were unrealized losses,$21.9 million were realized losses on settled derivative contracts and$1.8 million were unrealized gains related to the Haynesville Divestiture (refer to Note 7 - Derivative Contracts, in Item I of Part I of the Quarterly Report on Form 10-Q for more information). Gain on early extinguishment of debt. Gain on early extinguishment of debt increased by$0.4 million in the second quarter of 2020 compared to the second quarter of 2019. The increase during the second quarter of 2020 was primarily due to a$2.1 million gain as a result of repurchasing$57.0 million in principal amount of our senior notes at a discount, partially offset by a$1.5 million loss associated with the write-off of non-cash deferred financing costs as part of amending the credit facility (Refer to Note 10 - Debt, in Item 1 of Part I of this Quarterly Report on Form 10-Q for more information). Gain on early extinguishment of debt increased by$25.6 million in the first half of 2020 compared to the first half of 2019. The increase during the first half of 2020 was primarily due to a$27.5 million gain as a result of repurchasing$155.2 million in principal amount of our senior notes at a discount, partially offset by a$1.5 million loss associated with the write-off of non-cash deferred financing costs as part of amending the credit facility (Refer to Note 10 - Debt, in Item 1 of Part I of this Quarterly Report on Form 10-Q for more information). Interest and other income (expense). Interest and other income (expense) increased by$1.7 million , or 189%, during the second quarter of 2020 compared to the second quarter of 2019. The increase was primarily related to a$2.4 million gain on the marketable securities associated with its nonqualified, unfunded deferred compensation plan, partially offset by a$0.7 million loss on the write-off of inventory. Interest and other income (expense) decreased by$3.7 million , or 100%, during the first half of 2020 compared to the first half of 2019. The decrease was primarily related to a$2.6 million loss on the marketable securities associated with its nonqualified, unfunded deferred compensation plan and a$0.7 million loss on the write-off of inventory. Interest expense. Interest expense decreased$3.4 million , or 10%, during the second quarter of 2020 compared to the second quarter of 2019. The decrease during the second quarter of 2020 was primarily related to decreased interest expense on senior notes due to repurchases, a reduction of accrued interest on the Company's uncertain tax position that expired in the fourth quarter of 2019 and decreased borrowings under the credit facility. Interest expense decreased$5.8 million , or 9%, during the first half of 2020 compared to the first half of 2019. The decrease during the first half of 2020 was primarily related to decreased interest expense on senior notes due to repurchases, a reduction of accrued interest on the Company's uncertain tax position that expired in the fourth quarter of 2019 and decreased borrowings under the credit facility. Income tax (provision) benefit. Income tax expense decreased$83.3 million and was a benefit during the second quarter of 2020 compared to an expense during the second quarter of 2019. The decrease in expense was primarily the result of having a pre-tax loss during the second quarter of 2020 compared to pre-tax income in 2019. QEP's effective federal and state income tax rate was 22.5% during the second quarter of 2020 compared to a rate of 37.8% during the second quarter of 2019. The decrease in the federal and state income tax rate was primarily driven by the impact of discrete items recognized during the second quarter of 2019. The primary discrete item recognized during the second quarter of 2019 related to non-deductible executive compensation. 43 -------------------------------------------------------------------------------- Income tax benefit decreased$95.0 million during the first half of 2020 compared to the first half of 2019. The decrease in benefit was the result of having pre-tax income during the first half of 2020 compared to a pre-tax loss in 2019. QEP's effective federal and state income tax rate was 6.5% during the first half of 2020 compared to a rate of 54.8% during the first half of 2019. The decrease in the federal and state income tax rate was primarily driven by the impact of discrete items recognized during the first half of 2020 and 2019. The primary discrete items recognized during the first half of 2020 related to the remeasurement of deferred taxes due to a NOL carryback under the CARES Act to a year with a higher federal tax rate. The primary discrete items recognized during the first half of 2019 related to the remeasurement of deferred taxes associated with the Haynesville Divestiture and non-deductible executive compensation.
LIQUIDITY AND CAPITAL RESOURCES
QEP strives to maintain sufficient liquidity to ensure financial flexibility, withstand commodity price volatility and fund its development projects, operations and capital expenditures and return capital to shareholders. The Company utilizes derivative contracts to reduce the financial impact of commodity price volatility and provide a level of certainty to the Company's cash flows. QEP generally funds its operations and planned capital expenditures with cash flow from its operating activities, cash on hand and borrowings under its revolving credit facility. QEP also periodically accesses debt and equity markets and sells properties to enhance its liquidity. In an effort to preserve our liquidity, inMarch 2020 , the Board indefinitely suspended the payment of quarterly dividends. The Company expects that the annual generation of Free Cash Flow, cash on hand, anticipated AMT credit refunds and, as needed, borrowings made under its revolving credit facility, will be sufficient to fund its operations, capital expenditures, interest expense and debt maturities, including$275.3 million of Senior Notes dueMarch 1, 2021 , during the next 12 months. To the extent that the Company sells additional assets, the Company plans to use the proceeds to fund on-going operations, reduce debt and for general corporate purposes. During the six months endedJune 30, 2020 , QEP received cash proceeds from the disposition of assets of$12.9 million . QEP used the proceeds to repurchase a portion of its senior notes and for general corporate purposes. As ofJune 30, 2020 , the Company had$3.4 million in cash and cash equivalents, no borrowings under its revolving credit facility and$10.9 million in letters of credit outstanding. The Company estimates that as ofJune 30, 2020 , it could borrow up to$742.5 million under its credit facility and incur up to$500.0 million of junior guaranteed indebtedness and remain in compliance with its financial covenants (as defined in the credit agreement). To the extent actual operating results, realized commodity prices, receipt of AMT credit refunds or uses of cash differ from the Company's assumptions, QEP's liquidity could be adversely affected. Further, we may from time to time seek to retire, amend or restructure some or all of our outstanding debt or debt agreements through cash purchases, exchanges, open market purchases, privately negotiated transactions, tender offers or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. Credit Facility InJune 2020 , QEP entered into the Eighth Amendment to its credit agreement, which, among other things, reduced the aggregate principal amount of commitments to$850.0 million , requires the Company's material subsidiaries to guarantee the obligations under the credit agreement as well as certain swap obligations and modified the leverage ratio and present value financial covenants, such that they only pertain to net priority guaranteed debt (primarily consisting of borrowings under the credit facility and letters of credit). The amended credit agreement also provides the ability to use up to$500.0 million of loan proceeds to repurchase outstanding senior notes, provides the ability to issue subsidiary guarantees of up to$500.0 million of unsecured debt, with such guarantees being subordinated to the obligations under the credit agreement, and may limit the Company's ability to make certain restricted payments, including dividends. The amended credit agreement, which matures onSeptember 1, 2022 , provides for borrowings at short-term interest rates and contains customary covenants and restrictions and contains financial covenants (that are defined in the credit agreement) that limit the amount of debt the Company can incur and may limit the amount available to be drawn under the credit facility including: (i) a minimum liquidity amount of at least$100.0 million (ii) a net priority guaranteed leverage ratio under which net priority guaranteed debt may not exceed 2.50 times consolidated EBITDAX (as defined in the credit agreement), and (iii) a present value coverage ratio under which the present value of the Company's proved reserves must exceed net priority guaranteed debt by at least 1.50 times at any time on or afterJune 4, 2020 . AtJune 30, 2020 andDecember 31, 2019 , QEP was in compliance with the covenants under its credit agreement. The Company recorded a$1.5 million loss associated with the write-off of non-cash deferred financing costs as part of amending the credit facility and recorded the loss within "Gain from early extinguishment of debt" on the statements of operations. As ofJune 30, 2020 , QEP had no borrowings outstanding and$10.9 million in letters of credit outstanding under the credit facility. As ofJuly 22, 2020 , QEP had no borrowings outstanding and had$10.9 million in letters of credit outstanding under the credit facility and was in compliance with the covenants under the credit agreement. 44 -------------------------------------------------------------------------------- Senior Notes The Company's senior notes outstanding as ofJune 30, 2020 totaled a principal amount of$1,877.2 million and are comprised of four issuances as follows:
•$275.3 million 6.875% Senior Notes due
During the six months endedJune 30, 2020 , QEP repurchased principal amounts of$107.1 million of its 6.875% Senior Notes dueMarch 2021 ,$34.9 million of its 5.375% Senior Notes dueOctober 1, 2022 and$13.2 million of its 5.25% Senior Notes dueMay 1, 2023 . The Company recorded$27.5 million in "Gain from early extinguishment of debt" on the statements of operations primarily associated with the repurchase of Senior Notes during the period endedJune 30, 2020 .
The Company expects to fund the maturity of its 6.875% Senior Notes due
Cash Flow from Operating Activities
Cash flows from operating activities are primarily affected by oil and condensate, gas and NGL production volumes and commodity prices (including the effects of settlements of the Company's derivative contracts) and by changes in working capital. QEP typically enters into commodity derivative transactions covering a substantial, but varying, portion of its anticipated future oil and gas production for the next 12 to 24 months.
Net cash provided by (used in) operating activities is presented below:
Six Months Ended June 30,
2020 2019 Change
(in millions)
Net income (loss) $ 183.0 $ (67.9) $ 250.9
Non-cash adjustments to net income (loss) 224.5 296.5 (72.0)
Changes in operating assets and liabilities (183.1)
(32.9) (150.2)
Net cash provided by (used in) operating activities
Net cash provided by operating activities was$224.4 million during the first half of 2020, which included$183.0 million of net income,$224.5 million of non-cash adjustments to net income and$183.1 million in changes in operating assets and liabilities. Non-cash adjustments to net income of$224.5 million primarily included DD&A expense of$291.6 million and deferred income tax of$141.4 million , partially offset by$188.2 million of unrealized gains on derivative contracts and$25.6 million of gains from early extinguishment of debt.
The changes in operating assets and liabilities of
Net cash provided by operating activities was$195.7 million during the first half of 2019, which included$67.9 million of net loss,$296.5 million of non-cash adjustments to the net loss and$32.9 million in changes in operating assets and liabilities. Non-cash adjustments to the net loss of$296.5 million primarily included DD&A expense of$251.3 million ,$121.3 million of unrealized losses on derivative contracts, and$11.2 million of non-cash share-based compensation expense, partially offset by$87.7 million of deferred income tax benefit and net gain from assets sales, inclusive of restructuring costs, of$4.6 million . The decrease in changes in operating assets and liabilities of$32.9 million primarily resulted from decreases in accounts payable and accrued expenses of$54.0 million , partially offset by a decrease in accounts receivable of$21.2 million . 45 --------------------------------------------------------------------------------
Cash Flow from Investing Activities
A comparison of capital expenditures for the first half of 2020 and 2019, are presented in the table below:
Six Months Ended June 30,
2020 2019 Change
(in millions)
Property acquisitions $ 4.1 $ 1.8 $ 2.3
Property, plant and equipment capital expenditures 215.1 337.1 (122.0)
Total accrued capital expenditures 219.2 338.9 (119.7)
Change in accruals and other non-cash adjustments $ 30.7 $ (20.3) $ 51.0
Total cash capital expenditures $ 249.9 $
318.6
In the first half of 2020, on an accrual basis, the Company invested$215.1 million on property, plant and equipment capital expenditures (which excludes property acquisitions), a decrease of$122.0 million compared to the first half of 2019. In the first half of 2020, QEP's primary capital expenditures included$159.6 million in thePermian Basin (including midstream infrastructure of$9.9 million , primarily related to oil and gas gathering and water handling) and$54.5 million in theWilliston Basin . In the first half of 2019, on an accrual basis, the Company invested$337.1 million on property, plant and equipment capital expenditures (which excludes property acquisitions). QEP's significant capital expenditures included$307.0 million in thePermian Basin (including midstream infrastructure of$32.9 million , primarily related to oil and gas gathering and water handling), and$31.0 million in theWilliston Basin . The mid-point of our 2020 forecasted capital expenditures (excluding property acquisitions) is$360.0 million . QEP intends to fund capital expenditures (excluding property acquisitions) with cash on hand, cash flow from operating activities and proceeds from our derivative portfolio. The aggregate levels of capital expenditures for 2020 and the allocation of those expenditures are dependent on a variety of factors, including the continued impact on the market due to the COVID-19 pandemic andOPEC actions, oil, gas and NGL prices, industry conditions, changes in management's business assessments as to where QEP's capital can be most profitably deployed, drilling results, the extent to which properties or working interests are acquired or divested and the availability of capital resources to fund the expenditures. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from QEP's estimates.
Cash Flow from Financing Activities
In the first half of 2020, net cash used in financing activities was$149.6 million compared to net cash used in financing activities of$445.6 million in the first half of 2019. During the first half of 2020, QEP used$127.7 million of cash to repurchase senior notes and pay a quarterly dividend of$4.8 million . During the first half of 2020, QEP had a decrease in checks outstanding in excess of cash balances of$15.9 million . During the first half of 2019, QEP made repayments on its credit facility of$486.0 million and had borrowings from its credit facility of$56.0 million . In addition, QEP had treasury stock repurchases of$6.3 million related to the settlement of income tax and related benefit withholding obligations arising from the vesting of restricted share grants. During the first half of 2019, QEP had a decrease in checks outstanding in excess of cash balances of$9.3 million . As ofJune 30, 2020 , the total amount of long-term debt was$1,864.3 million , of which$1,877.2 million was the principal amount of its senior notes and$12.9 million was net original issue discount and unamortized debt issuance costs.
Off-Balance Sheet Arrangements
QEP may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. AtJune 30, 2020 , the Company's material off-balance sheet arrangements included drilling, gathering, processing and firm transportation arrangements and undrawn letters of credit. There are no other off-balance sheet arrangements that have or are reasonably likely to have a current or future material effect on QEP's financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources. For more information regarding off-balance sheet arrangements, we refer you to "Contractual Cash Obligations and Other Commitments" in our 2019 Annual Report on Form 10-K. 46 --------------------------------------------------------------------------------
Contractual Cash Obligations and Other Commitments
We have various contractual obligations in the normal course of our operations
and financing activities. There have been no material changes to our contractual
obligations from those disclosed in our 2019 Annual Report on Form 10-K.
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