ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 Condensed Consolidated 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 ended December 31, 2018 (2018 Form 10-K) and analyzes the changes in the results of operations between the three and nine months ended September 30, 2019 and 2018. 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 2018 Form 10-K.
OVERVIEW
QEP Resources, Inc. is an independent crude oil and natural gas exploration and production company with operations in two regions of the United States: the Southern Region (primarily in Texas) and the Northern Region (primarily in North Dakota). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "QEP".
In February 2019, QEP's Board of Directors commenced a comprehensive review of strategic alternatives to maximize shareholder value, which included the evaluation of a merger, sale of the Company or other transaction involving the Company's assets. In August 2019, QEP's Board of Directors completed their comprehensive review of strategic alternatives and determined that the best alternative for QEP's shareholders was to move forward as an independent company.
QEP's strategy incorporates a continued focus on high-return investments in its business with disciplined production growth. QEP is committed to strengthening its balance sheet, reducing leverage and returning capital to shareholders. QEP plans to fulfill this commitment by continuing to reassess its organizational needs and reducing its general and administrative expense to ensure its cost structure is competitive with industry peers, while continuing to lower its lease operating expense and drilling, completion and facility costs. All of this is underpinned by the improved performance and deliverability of our high-quality, oil-weighted asset base.
As a part of the 2018 and 2019 strategic initiatives, QEP has incurred or expects to incur additional 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. During the first three quarters of 2019, the Company incurred $36.7 million of general and administrative restructuring costs related to organizational changes and additional legal and outside professional costs of $6.5 million associated with the evaluation of strategic alternatives.
Acquisitions and Divestitures
While we believe our inventory of identified drilling locations provides a solid base for growth in production and reserves, we will continue to evaluate and acquire properties in our operating areas to add additional development opportunities and facilitate the drilling of long lateral wells.
Acquisitions
During the nine months ended September 30, 2019, QEP acquired various oil and gas properties, which primarily included proved acreage in the Permian Basin for an aggregate purchase price of $3.6 million, subject to post-closing purchase price adjustments.
During the nine months ended September 30, 2018, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage in the Permian Basin for an aggregate purchase price of $48.3 million. Of the $48.3 million, $37.6 million was related to acquisitions from various entities that owned additional oil and gas interests in certain properties included in the 2017 acquisition of oil and gas properties in the Permian Basin (2017 Permian Basin Acquisition) on substantially the same terms and conditions as the 2017 Permian Basin Acquisition in the fourth quarter of 2017.
Divestitures
In January 2019, QEP closed the sale of its assets in Haynesville/Cotton Valley (Haynesville Divestiture) and in July 2019 reached final settlement on asserted title defects. QEP received net cash proceeds of $633.9 million during the nine months ended September 30, 2019. Additionally, a total pre-tax loss on sale of $4.0 million was recognized. 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 nine months ended September 30, 2019, QEP received net cash proceeds of $42.6 million and recorded a net pre-tax gain on sale of $3.5 million, primarily related to the divestiture of properties outside our main operating areas, partially offset by the sale of the corporate aircraft.
In September 2018, QEP sold its natural gas and oil producing properties, undeveloped acreage and related assets located in the Uinta Basin for net cash proceeds of $153.0 million (Uinta Basin Divestiture). During the nine months ended September 30, 2019, QEP recorded a pre-tax loss on sale of $0.2 million due to post-closing purchase price adjustments, which was recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs". Refer to Note 1 – Basis of Presentation and 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 Uinta Basin Divestiture, during the nine months ended September 30, 2018, QEP recorded net cash proceeds of $64.5 million which resulted in a net pre-tax gain on sale of $39.1 million related to the divestiture of properties outside our main operating areas.
Financial and Operating Highlights
During the three months ended September 30, 2019, QEP:
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•
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Generated net income of $81.0 million, or $0.34 per diluted share;
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•
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Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $193.5 million;
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•
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Reported record oil and condensate production of 4.0 MMbbls in the Permian Basin, an increase of 12% compared to the third quarter 2018;
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•
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Reduced capital expenditures by $120.8 million compared to the third quarter 2018
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•
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Reinstated a quarterly cash dividend of $0.02 per share of common stock, which was paid in September 2019; and
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•
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Reduced general and administrative expenses by 39% compared to the third quarter 2018.
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During the nine months ended September 30, 2019, QEP:
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•
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Generated net income of $13.1 million, or $0.06 per diluted share;
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•
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Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $479.8 million;
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•
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Closed the Haynesville Divestiture for a total purchase price of $633.9 million;
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•
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Increased oil and condensate production in the Permian Basin by 14% to 10.1 MMbbls compared to the first three quarters of 2018;
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Reduced capital expenditures by $611.6 million compared to the first three quarters of 2018; and
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•
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Reduced general and administrative expenses by 24% compared to the first three quarters of 2018.
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Outlook
Based on current commodity prices, we expect to be able to fund our planned capital program for 2019 with cash flow from operating activities, cash on hand and, if needed, borrowings under our credit facility. Our total capital expenditures (excluding property acquisitions) for 2019 are expected to be approximately $574.5 million, a decrease of approximately 51% from 2018 capital expenditures. We continuously evaluate our level of drilling and completion activity in light of drilling results, commodity prices 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
Shareholder Activism
Elliott Management Corporation (Elliott), is a beneficial holder of approximately 4.9% of our common stock (based on Elliott's Form 13F-HR filed on August 14, 2019). Elliott has actively engaged in discussions with us regarding certain aspects of our business and operations. In addition, on January 7, 2019, Elliott made a proposal to our Board of Directors to acquire all of our outstanding shares of common stock. As a result of that proposal, our Board of Directors engaged in a comprehensive review of strategic alternatives and concluded that the best alternative for QEP's shareholders was to move forward as an independent company, and the Company entered into an agreement with affiliates of Elliott. Our business and/or operations could be adversely affected by any future actions of activist shareholders. Responding to actions by activist shareholders could be costly and time-consuming, disrupting our operations and diverting the attention of our management and employees. Activities of activist shareholders could interfere with our ability to execute our strategic plan or realize short- or long-term value from our assets.
Supply, Demand, Market Risk and their Impact on Oil Prices
Oil prices are affected by many factors outside of our control, including changes in supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of the U.S. dollar and other factors. In recent years, oil prices have been affected by supply growth, particularly in the U.S., driven by advances in drilling and completion technologies, and fluctuations in demand driven by a variety of factors.
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. Historically, field-level prices received for QEP's oil production have been volatile. During the past five years, the posted price for WTI crude oil has ranged from a low of $26.19 per barrel in February 2016 to a high of $91.02 per barrel in October 2014. If oil prices decline to early 2016 levels or further, our operations, financial condition and level of expenditures for the development of our oil reserves may be materially and adversely affected.
Global Geopolitical and Macroeconomic Factors
QEP continues to monitor the global economy, including Europe and China's economic outlook; the Organization of Petroleum Exporting Countries (OPEC) countries' oil production and policies regarding production quotas; political unrest and global economic issues; slowing growth in certain emerging market economies; actions taken by the United States Congress and the president of the United States; the U.S. federal budget deficit; changes in regulatory oversight policy; 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 could have a significant impact on oil, gas and NGL supply, demand and prices and the Company's ability to continue its planned drilling programs and 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. At September 30, 2019, QEP forecasted the midpoint of its 2019 annual production to be approximately 32.3 MMboe and had approximately 68% of its forecasted oil and condensate production covered with fixed-price swaps. 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, 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 fair value 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 nine months ended September 30, 2019, the Company recorded impairment charges of $5.0 million related to an office building lease.
During the nine months ended September 30, 2018, QEP recorded impairment charges of $404.4 million, of which $402.8 million of proved and unproved properties impairment was triggered by the Uinta Basin Divestiture and $1.6 million was related to expiring leaseholds on unproved properties and impairment of proved properties related to a divestiture in the Other Northern area.
We could be at risk for proved and unproved property and operating lease right-of-use asset impairments if forward oil prices decline from September 30, 2019 levels, we experience negative changes in estimated reserve quantities or from our strategic initiative results. The actual amount of impairment incurred, if any, for these 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 the properties, weighted-average cost of capital, operating cost estimates and future capital expenditure estimates.
Income Tax
The Tax Legislation enacted in December 2017 reduced our federal corporate tax rate from 35% to 21%. In addition, the Tax Legislation eliminated Alternative Minimum Tax (AMT) and allows the Company the ability to offset its regular tax liability or claim refunds for taxable years 2018 through 2021 for AMT credits carried forward from prior years. The Company currently anticipates it will realize approximately $148.4 million in AMT credit refunds. The Company expects to receive the $148.4 million over the next four years, including $74.2 million in 2019. The amount expected to be refunded in 2019 is included in "Income tax receivable" with the remaining $74.2 million included in "Deferred income taxes" on the Condensed Consolidated Balance Sheet as of September 30, 2019.
As of September 30, 2019, QEP had $19.0 million in uncertain tax positions related to asset sales that occurred in 2014, which were recorded within "Other long-term liabilities" on the Condensed Consolidated Balance Sheet. The uncertain tax position was recognized as income tax expense during the year ended December 31, 2014, with an additional income tax expense recognized during 2017 as a result of the Tax Legislation changes. The statute of limitations related to the uncertain tax position expires in the fourth quarter of 2019, and upon expiration, the Company expects to recognize a $19.0 million tax benefit as well as record a $3.6 million reduction in "Interest expense" and a $2.8 million reduction in "General and administrative" expense on the Consolidated Statements of Operations related to accrued interest and penalties that were previously recorded in prior periods.
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 the Permian 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 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 and the commencement of production. 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 conversion 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.
Critical Accounting Estimates
QEP's significant accounting policies are described in Item 7 of Part II of its 2018 Form 10-K. The Company's Condensed Consolidated Financial Statements are prepared in accordance with GAAP. The preparation of the Company's Condensed Consolidated 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, asset retirement obligations, revenue recognition, litigation and other contingencies, derivative contracts, pension and other postretirement benefits, share-based compensation, income taxes and purchase price allocations, among others, may involve a high degree of complexity and judgment on the part of management.
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 of September 30, 2019:
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Operated
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Non-operated
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Drilling
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Drilling
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Waiting on completion
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Drilling
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Waiting on completion
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Rigs
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Gross
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Net
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Gross
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Net
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Gross
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Net
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Gross
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Net
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Northern Region
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Williston Basin
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—
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—
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—
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4
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3.4
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—
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—
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12
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0.8
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Southern Region
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Permian Basin(1)
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2
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7
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7.0
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31
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31.0
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—
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—
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—
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—
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____________________________
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(1)
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Five of the seven gross operated drilling wells in the Permian Basin represent wells for which surface casing had been set as of September 30, 2019.
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Each gross well completed in more than one producing zone is counted as a single well. Delays and well shut-ins resulting from multi-well pad drilling have caused and may continue to cause volatility in QEP's quarterly operating results. In addition, delays in completion of wells could impact planned conversion of PUD reserves to proved developed reserves. QEP had 35 gross operated wells waiting on completion as of September 30, 2019.
The following table presents the number of operated and non-operated wells completed and turned to sales (put on production) for the three and nine months ended September 30, 2019:
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Operated Put on Production
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Non-operated Put on Production
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Three Months Ended
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Nine Months Ended
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Three Months Ended
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Nine Months Ended
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September 30, 2019
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September 30, 2019
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September 30, 2019
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September 30, 2019
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Gross
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Net
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Gross
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Net
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Gross
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Net
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Gross
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Net
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Northern Region
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Williston Basin
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3
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3.0
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3
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3.0
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3
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1.0
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8
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1.1
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Southern Region
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Permian Basin
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24
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24.0
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59
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58.9
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—
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—
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5
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0.4
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The following table presents the number of operated wells in the process of being drilled or waiting on completion at September 30, 2019 and operated wells completed and turned to sales (put on production) for the nine months ended September 30, 2019:
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Permian Basin
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Williston Basin
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As of September 30, 2019
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Gross
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Net
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Gross
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Net
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Well Progress
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Drilling
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7
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7.0
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—
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—
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At total depth - under drilling rig
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6
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6.0
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—
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—
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Waiting to be completed
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25
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25.0
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—
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—
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Completed, awaiting production
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—
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—
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4
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3.4
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Waiting on completion
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31
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31.0
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4
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3.4
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Put on production
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59
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58.9
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3
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3.0
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RESULTS OF OPERATIONS
Net Income
QEP generated net income during the third quarter of 2019 of $81.0 million or $0.34 per diluted share, compared to a net income of $7.3 million or $0.03 per diluted share, in the third quarter of 2018. QEP's increase in net income in the third quarter of 2019 compared to 2018 was primarily due to an $87.4 million gain on realized and unrealized derivative contracts in the third quarter of 2019.
During the first three quarters of 2019, QEP generated net income of $13.1 million or $0.06 per diluted share, compared to net loss of $382.3 million or $1.60 per diluted share, in the first three quarters of 2018. QEP generated more income in the first three quarters of 2019 than in 2018 primarily due to $404.4 million impairment expense and a $240.3 million loss on realized and unrealized derivative contracts recorded in the first three quarters of 2018.
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 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 would reduce the usefulness of this non-GAAP financial measure when comparing our performance to that of other companies.
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.
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Three Months Ended September 30,
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Nine Months Ended September 30,
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2019
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2018
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2019
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2018
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(in millions)
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Net income (loss)
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$
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81.0
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$
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7.3
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$
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13.1
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$
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(382.3
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)
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Interest expense
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32.8
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38.7
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|
100.0
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111.9
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Interest and other (income) expense
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(0.9
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)
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0.3
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(4.6
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)
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4.1
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Income tax provision (benefit)
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26.6
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2.5
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(55.7
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)
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(117.6
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)
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Depreciation, depletion and amortization
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144.2
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234.9
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395.5
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673.6
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Unrealized (gains) losses on derivative contracts
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(92.3
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)
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69.6
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29.0
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113.2
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Exploration expenses
|
—
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—
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—
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0.1
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Net (gain) loss from asset sales, inclusive of restructuring costs
|
2.1
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(27.1
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)
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(2.5
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)
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(26.7
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)
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Impairment
|
—
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|
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—
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|
|
5.0
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|
|
404.4
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|
|
Adjusted EBITDA
|
$
|
193.5
|
|
|
$
|
326.2
|
|
|
$
|
479.8
|
|
|
$
|
780.7
|
|
In the third quarter of 2019, Adjusted EBITDA decreased to $193.5 million compared to $326.2 million in the third quarter of 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures, lower equivalent production in the Williston Basin and an 16% decrease in average field-level oil prices, partially offset by an 18% increase in equivalent production in the Permian Basin, a $33.5 million decrease in realized derivative losses and $18.7 million decrease in general and administrative expenses.
In the first three quarters of 2019, Adjusted EBITDA decreased to $479.8 million compared to $780.7 million in the first three quarters of 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures, lower equivalent production in the Williston Basin and a 15% decrease in average field-level oil prices, partially offset by a 23% increase in equivalent production in the Permian Basin, a $100.3 million decrease in realized derivative losses and $39.8 million decrease in general and administrative expenses.
Revenue
The following table presents our revenues disaggregated by revenue source.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
September 30,
|
|
September 30,
|
|
|
2019
|
|
2018
|
|
Change
|
|
2019
|
|
2018
|
|
Change
|
|
|
(in millions)
|
|
Oil and condensate, gas and NGL sales, as presented
|
$
|
305.6
|
|
|
$
|
544.0
|
|
|
$
|
(238.4
|
)
|
|
$
|
875.8
|
|
|
$
|
1,474.1
|
|
|
$
|
(598.3
|
)
|
|
Transportation and processing costs included in revenue(1)
|
14.2
|
|
|
15.8
|
|
|
(1.6
|
)
|
|
40.7
|
|
|
40.9
|
|
|
(0.2
|
)
|
|
Oil and condensate, gas and NGL sales, as adjusted(2)
|
319.8
|
|
|
$
|
559.8
|
|
|
$
|
(240.0
|
)
|
|
$
|
916.5
|
|
|
$
|
1,515.0
|
|
|
$
|
(598.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate sales
|
$
|
298.8
|
|
|
$
|
416.1
|
|
|
$
|
(117.3
|
)
|
|
$
|
834.0
|
|
|
$
|
1,125.3
|
|
|
$
|
(291.3
|
)
|
|
Gas sales
|
9.1
|
|
|
101.7
|
|
|
(92.6
|
)
|
|
39.4
|
|
|
301.5
|
|
|
(262.1
|
)
|
|
NGL sales
|
11.9
|
|
|
42.0
|
|
|
(30.1
|
)
|
|
43.1
|
|
|
88.2
|
|
|
(45.1
|
)
|
|
Oil and condensate, gas and NGL sales, as adjusted(2)
|
$
|
319.8
|
|
|
559.8
|
|
|
$
|
(240.0
|
)
|
|
$
|
916.5
|
|
|
$
|
1,515.0
|
|
|
$
|
(598.5
|
)
|
____________________________
|
|
|
|
(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 Condensed Consolidated 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 nine months ended September 30, 2019, compared to the three and nine months ended September 30, 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate
|
|
Gas
|
|
NGL
|
|
Total
|
|
|
(in millions)
|
|
Oil and condensate, gas and NGL sales, as adjusted
|
|
|
|
|
|
|
|
|
Three months ended September 30, 2018
|
$
|
416.1
|
|
|
$
|
101.7
|
|
|
$
|
42.0
|
|
|
$
|
559.8
|
|
|
Changes associated with volumes(1)
|
(60.9
|
)
|
|
(80.0
|
)
|
|
(1.0
|
)
|
|
(141.9
|
)
|
|
Changes associated with prices(2)
|
(56.4
|
)
|
|
(12.6
|
)
|
|
(29.1
|
)
|
|
(98.1
|
)
|
|
Three months ended September 30, 2019
|
$
|
298.8
|
|
|
$
|
9.1
|
|
|
$
|
11.9
|
|
|
$
|
319.8
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate, gas and NGL sales, as adjusted
|
|
|
|
|
|
|
|
|
Nine months ended September 30, 2018
|
$
|
1,125.3
|
|
|
$
|
301.5
|
|
|
$
|
88.2
|
|
|
$
|
1,515.0
|
|
|
Changes associated with volumes(1)
|
(141.0
|
)
|
|
(235.0
|
)
|
|
7.0
|
|
|
(369.0
|
)
|
|
Changes associated with prices(2)
|
(150.3
|
)
|
|
(27.1
|
)
|
|
(52.1
|
)
|
|
(229.5
|
)
|
|
Nine months ended September 30, 2019
|
$
|
834.0
|
|
|
$
|
39.4
|
|
|
$
|
43.1
|
|
|
$
|
916.5
|
|
____________________________
|
|
|
|
(1)
|
The revenue variance attributed to the change in volume is calculated by multiplying the change in volume from the three and nine months ended September 30, 2019, as compared to the three and nine months ended September 30, 2018, by the average field-level price for the three and nine months ended September 30, 2018.
|
|
|
|
|
(2)
|
The revenue variance attributed to the change in price is calculated by multiplying the change in average field-level price from the three and nine months ended September 30, 2019, as compared to the three and nine months ended September 30, 2018, by the respective volumes for the three and nine months ended September 30, 2019. Pricing changes are driven by changes in commodity average field-level prices, excluding the impact from commodity derivatives.
|
Production and Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2019
|
|
2018
|
|
Change
|
|
2019
|
|
2018
|
|
Change
|
|
Total production volumes (Mboe)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
2,722.5
|
|
|
4,381.1
|
|
|
(1,658.6
|
)
|
|
9,061.9
|
|
|
12,570.5
|
|
|
(3,508.6
|
)
|
|
Uinta Basin
|
—
|
|
|
606.0
|
|
|
(606.0
|
)
|
|
—
|
|
|
2,232.2
|
|
|
(2,232.2
|
)
|
|
Other Northern
|
19.4
|
|
|
63.1
|
|
|
(43.7
|
)
|
|
65.1
|
|
|
211.4
|
|
|
(146.3
|
)
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
5,658.5
|
|
|
4,792.5
|
|
|
866.0
|
|
|
14,293.2
|
|
|
11,591.6
|
|
|
2,701.6
|
|
|
Haynesville/Cotton Valley
|
(0.4
|
)
|
|
4,552.8
|
|
|
(4,553.2
|
)
|
|
310.5
|
|
|
13,604.6
|
|
|
(13,294.1
|
)
|
|
Other Southern
|
4.0
|
|
|
4.5
|
|
|
(0.5
|
)
|
|
14.3
|
|
|
20.4
|
|
|
(6.1
|
)
|
|
Total production
|
8,404.0
|
|
|
14,400.0
|
|
|
(5,996.0
|
)
|
|
23,745.0
|
|
|
40,230.7
|
|
|
(16,485.7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equivalent prices (per Boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
Average field-level equivalent price
|
$
|
38.06
|
|
|
$
|
38.87
|
|
|
$
|
(0.81
|
)
|
|
$
|
38.60
|
|
|
$
|
37.66
|
|
|
$
|
0.94
|
|
|
Commodity derivative impact
|
(0.59
|
)
|
|
(2.66
|
)
|
|
2.07
|
|
|
(1.13
|
)
|
|
(3.16
|
)
|
|
2.03
|
|
|
Net realized equivalent price
|
$
|
37.47
|
|
|
$
|
36.21
|
|
|
$
|
1.26
|
|
|
$
|
37.47
|
|
|
$
|
34.50
|
|
|
$
|
2.97
|
|
Oil and Condensate Volumes and Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2019
|
|
2018
|
|
Change
|
|
2019
|
|
2018
|
|
Change
|
|
Oil and condensate production volumes (Mbbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
1,700.3
|
|
|
2,968.6
|
|
|
(1,268.3
|
)
|
|
5,719.7
|
|
|
8,747.6
|
|
|
(3,027.9
|
)
|
|
Uinta Basin
|
—
|
|
|
124.7
|
|
|
(124.7
|
)
|
|
—
|
|
|
445.0
|
|
|
(445.0
|
)
|
|
Other Northern
|
12.1
|
|
|
19.8
|
|
|
(7.7
|
)
|
|
36.1
|
|
|
76.8
|
|
|
(40.7
|
)
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
3,956.5
|
|
|
3,525.7
|
|
|
430.8
|
|
|
10,144.9
|
|
|
8,892.0
|
|
|
1,252.9
|
|
|
Haynesville/Cotton Valley
|
—
|
|
|
1.9
|
|
|
(1.9
|
)
|
|
—
|
|
|
12.2
|
|
|
(12.2
|
)
|
|
Other Southern
|
1.6
|
|
|
(0.2
|
)
|
|
1.8
|
|
|
3.7
|
|
|
8.5
|
|
|
(4.8
|
)
|
|
Total production
|
5,670.5
|
|
|
6,640.5
|
|
|
(970.0
|
)
|
|
15,904.4
|
|
|
18,182.1
|
|
|
(2,277.7
|
)
|
|
Average field-level oil prices (per bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
$
|
51.92
|
|
|
$
|
68.06
|
|
|
$
|
(16.14
|
)
|
|
$
|
53.38
|
|
|
$
|
64.80
|
|
|
$
|
(11.42
|
)
|
|
Southern Region
|
$
|
53.03
|
|
|
$
|
57.88
|
|
|
$
|
(4.85
|
)
|
|
$
|
51.91
|
|
|
$
|
58.87
|
|
|
$
|
(6.96
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average field-level price
|
$
|
52.70
|
|
|
$
|
62.65
|
|
|
$
|
(9.95
|
)
|
|
$
|
52.44
|
|
|
$
|
61.89
|
|
|
$
|
(9.45
|
)
|
|
Commodity derivative impact
|
(0.87
|
)
|
|
(6.27
|
)
|
|
5.40
|
|
|
(1.50
|
)
|
|
(7.59
|
)
|
|
6.09
|
|
|
Net realized price
|
$
|
51.83
|
|
|
$
|
56.38
|
|
|
$
|
(4.55
|
)
|
|
$
|
50.94
|
|
|
$
|
54.30
|
|
|
$
|
(3.36
|
)
|
Oil and condensate revenues decreased $117.3 million, or 28%, in the third quarter of 2019 compared to the third quarter of 2018, due to lower average field-level prices and lower aggregate oil and condensate production volumes. Average field-level oil prices decreased 16% in the third quarter of 2019 compared to the third quarter of 2018 primarily driven by a decrease in average NYMEX-WTI oil prices for the comparable periods, partially offset by a $3.40 per bbl, or 48%, decrease in the basis differential relative to the average NYMEX-WTI oil price in the third quarter of 2019 compared to the third quarter of 2018. The 15% decrease in production volumes was primarily driven by a decrease in production in the Williston Basin due to a reduced level of activity in the third quarter of 2019 and the Uinta Basin Divestiture, partially offset by an increase in production in the Permian Basin due to continued drilling and completion activity.
Oil and condensate revenues decreased $291.3 million, or 26%, in the first three quarters of 2019 compared to the first three quarters of 2018, due to lower average field-level prices and lower aggregate oil and condensate production volumes. Average field-level oil prices decreased 15% in the first three quarters of 2019 compared to the first three quarters of 2018 primarily driven by a decrease in average NYMEX-WTI oil prices for the comparable periods, partially offset by a $0.46 per bbl, or 9%, decrease in the basis differential relative to the average NYMEX-WTI oil price in the first three quarters of 2019 compared to the first three quarters of 2018. The 13% decrease in production volumes was driven by a decrease in production in the Williston Basin due to a reduced level of activity in 2019 and the Uinta Basin Divestiture, partially offset by an increase in production in the Permian Basin due to continued drilling and completion activity.
Gas Volumes and Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2019
|
|
2018
|
|
Change
|
|
2019
|
|
2018
|
|
Change
|
|
Gas production volumes (Bcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
3.3
|
|
|
4.4
|
|
|
(1.1
|
)
|
|
10.6
|
|
|
11.6
|
|
|
(1.0
|
)
|
|
Uinta Basin
|
—
|
|
|
2.7
|
|
|
(2.7
|
)
|
|
—
|
|
|
10.1
|
|
|
(10.1
|
)
|
|
Other Northern
|
—
|
|
|
0.3
|
|
|
(0.3
|
)
|
|
0.1
|
|
|
0.8
|
|
|
(0.7
|
)
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
4.8
|
|
|
3.3
|
|
|
1.5
|
|
|
11.9
|
|
|
7.3
|
|
|
4.6
|
|
|
Haynesville/Cotton Valley
|
—
|
|
|
27.4
|
|
|
(27.4
|
)
|
|
1.9
|
|
|
81.6
|
|
|
(79.7
|
)
|
|
Other Southern
|
0.1
|
|
|
—
|
|
|
0.1
|
|
|
0.1
|
|
|
0.1
|
|
|
—
|
|
|
Total production
|
8.2
|
|
|
38.1
|
|
|
(29.9
|
)
|
|
24.6
|
|
|
111.5
|
|
|
(86.9
|
)
|
|
Average field-level gas prices (per Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
$
|
1.72
|
|
|
$
|
2.59
|
|
|
$
|
(0.87
|
)
|
|
$
|
2.41
|
|
|
$
|
2.52
|
|
|
$
|
(0.11
|
)
|
|
Southern Region
|
$
|
0.71
|
|
|
$
|
2.69
|
|
|
$
|
(1.98
|
)
|
|
$
|
0.98
|
|
|
$
|
2.75
|
|
|
$
|
(1.77
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average field-level price
|
$
|
1.13
|
|
|
$
|
2.67
|
|
|
$
|
(1.54
|
)
|
|
$
|
1.61
|
|
|
$
|
2.71
|
|
|
$
|
(1.10
|
)
|
|
Commodity derivative impact
|
—
|
|
|
0.09
|
|
|
(0.09
|
)
|
|
(0.12
|
)
|
|
0.10
|
|
|
(0.22
|
)
|
|
Net realized price
|
$
|
1.13
|
|
|
$
|
2.76
|
|
|
$
|
(1.63
|
)
|
|
$
|
1.49
|
|
|
$
|
2.81
|
|
|
$
|
(1.32
|
)
|
Gas revenues decreased $92.6 million, or 91%, in the third quarter of 2019 compared to the third quarter of 2018, due to lower gas production volumes and lower average field-level prices. Production volumes decreased 78% in the third quarter of 2019 compared to the third quarter of 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Average field-level gas prices decreased 58% in the third quarter of 2019 compared to the third quarter of 2018, primarily driven by a decrease in average NYMEX-HH gas spot prices and regional basis differentials in the Permian and Williston basins for the comparable periods.
Gas revenues decreased $262.1 million, or 87%, in the first three quarters of 2019 compared to the first three quarters of 2018, due to lower gas production volumes and lower average field-level prices. Production volumes decreased 78% in the first three quarters of 2019 compared to the first three quarters of 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures, partially offset by an increase in production in the Permian Basin due to continued drilling and completion activity. Average field-level gas prices decreased 41% in the first three quarters of 2019 compared to the first three quarters of 2018, primarily driven by a decrease in average NYMEX-HH gas spot prices and regional basis differentials for the comparable periods.
NGL Volumes and Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2019
|
|
2018
|
|
Change
|
|
2019
|
|
2018
|
|
Change
|
|
NGL production volumes (Mbbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
472.1
|
|
|
667.6
|
|
|
(195.5
|
)
|
|
1,577.5
|
|
|
1,885.7
|
|
|
(308.2
|
)
|
|
Uinta Basin
|
—
|
|
|
25.7
|
|
|
(25.7
|
)
|
|
—
|
|
|
96.9
|
|
|
(96.9
|
)
|
|
Other Northern
|
0.7
|
|
|
3.7
|
|
|
(3.0
|
)
|
|
1.1
|
|
|
9.4
|
|
|
(8.3
|
)
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
909.9
|
|
|
717.9
|
|
|
192.0
|
|
|
2,168.4
|
|
|
1,479.2
|
|
|
689.2
|
|
|
Haynesville/Cotton Valley
|
—
|
|
|
0.1
|
|
|
(0.1
|
)
|
|
—
|
|
|
0.4
|
|
|
(0.4
|
)
|
|
Other Southern
|
0.3
|
|
|
0.3
|
|
|
—
|
|
|
0.8
|
|
|
0.9
|
|
|
(0.1
|
)
|
|
Total production
|
1,383.0
|
|
|
1,415.3
|
|
|
(32.3
|
)
|
|
3,747.8
|
|
|
3,472.5
|
|
|
275.3
|
|
|
Average field-level NGL prices (per bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
$
|
5.26
|
|
|
$
|
29.55
|
|
|
$
|
(24.29
|
)
|
|
$
|
9.92
|
|
|
$
|
25.32
|
|
|
$
|
(15.40
|
)
|
|
Southern Region
|
$
|
10.38
|
|
|
$
|
29.74
|
|
|
$
|
(19.36
|
)
|
|
$
|
12.65
|
|
|
$
|
25.49
|
|
|
$
|
(12.84
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average field-level price
|
$
|
8.63
|
|
|
$
|
29.65
|
|
|
$
|
(21.02
|
)
|
|
$
|
11.50
|
|
|
$
|
25.39
|
|
|
$
|
(13.89
|
)
|
|
Commodity derivative impact
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Net realized price
|
$
|
8.63
|
|
|
$
|
29.65
|
|
|
$
|
(21.02
|
)
|
|
$
|
11.50
|
|
|
$
|
25.39
|
|
|
$
|
(13.89
|
)
|
NGL revenues decreased $30.1 million, or 72%, during the third quarter of 2019 compared to the third quarter of 2018, due to lower average field-level prices and lower NGL production volumes. The 71% decrease in NGL prices during the third quarter of 2019 compared to the third quarter of 2018 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 production decreases in the Williston Basin due to a reduced level of activity in 2019 and the Uinta Basin Divestiture, partially offset by continued drilling and completion activity in the Permian Basin.
NGL revenues decreased $45.1 million, or 51%, during the first three quarters of 2019 compared to the first three quarters of 2018, due to lower average field-level prices, partially offset by higher NGL production volumes. The 55% decrease in NGL prices during the first three quarters of 2019 compared to the first three quarters of 2018 was primarily driven by a decrease in propane, ethane and other NGL component prices. The decrease in price was partially offset by an 8% increase in NGL production volumes primarily driven by continued drilling and completion activity and higher gas capture rates as a result of the completion of our midstream infrastructure in the Permian Basin, partially offset by production decreases in the Williston Basin due to a reduced level of activity in 2019 and the Uinta Basin Divestiture.
Resale Margin and Storage Activity
QEP purchases and resells oil and gas primarily to mitigate credit risk related to third party purchasers, to fulfill volume commitments when our production does not fulfill contractual commitments and to capture additional margin from subsequent sales of third-party purchases. With the Pinedale and Uinta Basin divestitures in 2018 and the Haynesville Divestiture (which included our firm transportation agreements) in the first quarter of 2019, purchases and resale of gas are minimal going forward. The following table is a summary of QEP's financial results from its resale activities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2019
|
|
2018
|
|
Change
|
|
2019
|
|
2018
|
|
Change
|
|
|
(in millions)
|
|
Purchased oil and gas sales
|
$
|
0.1
|
|
|
$
|
13.0
|
|
|
$
|
(12.9
|
)
|
|
$
|
1.4
|
|
|
$
|
36.2
|
|
|
$
|
(34.8
|
)
|
|
Purchased oil and gas expense
|
(0.1
|
)
|
|
(13.3
|
)
|
|
13.2
|
|
|
(1.5
|
)
|
|
(38.6
|
)
|
|
37.1
|
|
|
Realized gains (losses) on gas storage derivative contracts
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.3
|
|
|
(0.3
|
)
|
|
Resale margin
|
$
|
—
|
|
|
$
|
(0.3
|
)
|
|
$
|
0.3
|
|
|
$
|
(0.1
|
)
|
|
$
|
(2.1
|
)
|
|
$
|
2.0
|
|
Purchased oil and gas sales and expense were lower in the third quarter of 2019 compared to the third quarter of 2018, primarily due to the fulfillment of a gas sales agreement related to Pinedale that was retained and not part of the Pinedale Divestiture, and fulfillment of our firm volume commitments in Haynesville/Cotton Valley, which were divested in January 2019.
Purchased oil and gas sales and expense were lower in the first three quarters of 2019 compared to the first three quarters of 2018, primarily due to the fulfillment of a gas sales agreement related to Pinedale that was retained and not part of the Pinedale Divestiture, and fulfillment of our firm volume commitments in Haynesville/Cotton Valley, which were divested in January 2019.
Operating Expenses
The following table presents QEP production costs and production costs on a per unit of production basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2019
|
|
2018
|
|
Change
|
|
2019
|
|
2018
|
|
Change
|
|
|
(in millions)
|
|
Lease operating expense
|
$
|
38.3
|
|
|
$
|
64.6
|
|
|
$
|
(26.3
|
)
|
|
$
|
135.5
|
|
|
$
|
203.6
|
|
|
$
|
(68.1
|
)
|
|
Adjusted transportation and processing costs(1)
|
32.2
|
|
|
43.8
|
|
|
(11.6
|
)
|
|
79.5
|
|
|
134.1
|
|
|
(54.6
|
)
|
|
Production and property taxes
|
20.0
|
|
|
37.4
|
|
|
(17.4
|
)
|
|
67.6
|
|
|
103.9
|
|
|
(36.3
|
)
|
|
Total production costs
|
$
|
90.5
|
|
|
$
|
145.8
|
|
|
$
|
(55.3
|
)
|
|
$
|
282.6
|
|
|
$
|
441.6
|
|
|
$
|
(159.0
|
)
|
|
|
(per Boe)
|
|
Lease operating expense
|
$
|
4.56
|
|
|
$
|
4.49
|
|
|
$
|
0.07
|
|
|
$
|
5.71
|
|
|
$
|
5.06
|
|
|
$
|
0.65
|
|
|
Adjusted transportation and processing costs(1)
|
3.83
|
|
|
3.04
|
|
|
0.79
|
|
|
3.34
|
|
|
3.34
|
|
|
—
|
|
|
Production and property taxes
|
2.38
|
|
|
2.60
|
|
|
(0.22
|
)
|
|
2.85
|
|
|
2.58
|
|
|
0.27
|
|
|
Total production costs
|
$
|
10.77
|
|
|
$
|
10.13
|
|
|
$
|
0.64
|
|
|
$
|
11.90
|
|
|
$
|
10.98
|
|
|
$
|
0.92
|
|
____________________________
|
|
|
|
(1)
|
Below are reconciliations of transportation and processing costs (the most comparable GAAP measure) as presented on the Condensed Consolidated 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 Condensed Consolidated 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 September 30,
|
|
Nine Months Ended September 30,
|
|
|
2019
|
|
2018
|
|
Change
|
|
2019
|
|
2018
|
|
Change
|
|
|
(in millions)
|
|
Transportation and processing costs, as presented
|
$
|
18.0
|
|
|
$
|
28.0
|
|
|
$
|
(10.0
|
)
|
|
$
|
38.8
|
|
|
$
|
93.2
|
|
|
$
|
(54.4
|
)
|
|
Transportation and processing costs deducted from oil and condensate, gas and NGL sales
|
14.2
|
|
|
15.8
|
|
|
(1.6
|
)
|
|
40.7
|
|
|
40.9
|
|
|
(0.2
|
)
|
|
Adjusted transportation and processing costs
|
$
|
32.2
|
|
|
$
|
43.8
|
|
|
$
|
(11.6
|
)
|
|
$
|
79.5
|
|
|
$
|
134.1
|
|
|
$
|
(54.6
|
)
|
|
|
(per Boe)
|
|
Transportation and processing costs, as presented
|
$
|
2.14
|
|
|
$
|
1.94
|
|
|
$
|
0.20
|
|
|
$
|
1.63
|
|
|
$
|
2.32
|
|
|
$
|
(0.69
|
)
|
|
Transportation and processing costs deducted from oil and condensate, gas and NGL sales
|
1.69
|
|
|
1.10
|
|
|
0.59
|
|
|
1.71
|
|
|
1.02
|
|
|
0.69
|
|
|
Adjusted transportation and processing costs
|
$
|
3.83
|
|
|
$
|
3.04
|
|
|
$
|
0.79
|
|
|
$
|
3.34
|
|
|
$
|
3.34
|
|
|
$
|
—
|
|
Lease operating expense (LOE). QEP's LOE decreased $26.3 million, or 41%, in the third quarter of 2019 compared to the third quarter of 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, LOE decreased $14.1 million, driven by a decrease in maintenance and repair expenses, labor and water disposal in the Permian and Williston basins as a result of continuing efforts to reduce operating expenses.
During the third quarter of 2019, LOE increased $0.07 per Boe, or 2%, compared to the third quarter of 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, LOE per Boe decreased by 20% compared to the third quarter of 2018. The 20% decrease per BOE rate was related to lower cost production from the recent horizontal well completions in the Permian Basin, partially offset by decreased production in the Williston Basin.
QEP's LOE decreased $68.1 million, or 33%, in the first three quarters of 2019 compared to the first three quarters of 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, LOE decreased $23.7 million, driven by a decrease in workovers, maintenance and repair expenses and water disposal in the Permian and Williston basins as a result of continuing efforts to reduce operating expenses.
During the first three quarters of 2019, LOE increased $0.65 per Boe, or 13%, compared to the first three quarters of 2018, but was down 11% excluding the loss of lower LOE production due to the Haynesville/Cotton Valley and Uinta Basin divestitures. The 11% per BOE decrease was related to lower cost production from the recent horizontal well completions in the Permian Basin, partially offset by decreased production in the Williston Basin.
Adjusted transportation and processing costs (non-GAAP). Adjusted transportation and processing costs decreased $11.6 million, or 26%, in the third quarter of 2019 compared to the third quarter of 2018. The decrease in expense was primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, adjusted transportation and processing costs increased $5.2 million, primarily due to the recognition of $7.7 million of firm transportation expense related to future obligations in an area in which the Company no longer has production operations as well as increased production in the Permian Basin, partially offset by decreased production in the Williston Basin.
During the third quarter of 2019, adjusted transportation and processing costs increased $0.79 per Boe, or 26%, compared to the third quarter of 2018. The increase was primarily due to the recognition of $7.7 million of firm transportation expense related to future obligations in an area in which the Company no longer has production operations, partially offset by the Haynesville/Cotton Valley and Uinta Basin divestitures, which had higher adjusted transportation and processing costs per Boe.
Adjusted transportation and processing costs decreased $54.6 million, or 41%, in the first three quarters of 2019 compared to the first three quarters of 2018. The decrease in expense was primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, adjusted transportation and processing costs increased $2.5 million, primarily due to the recognition of $7.7 million of firm transportation expense related to future obligations in an area in which the Company no longer has production operations and increased production in the Permian Basin, partially offset by decreased production in the Williston Basin.
During the first three quarters of 2019, adjusted transportation and processing costs remained flat per Boe compared to the first three quarters of 2018. The flat rate per Boe was primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures, which had higher adjusted transportation and processing costs per Boe. Excluding the Haynesville/Cotton Valley and Uinta Basin divestitures, adjusted transportation and processing costs per Boe were up 7% due to the recognition of $7.7 million of firm transportation expense related to future obligations in an area in which the Company no longer has production operations.
Production and property taxes. In most states in which QEP operates, QEP pays production taxes based on a percentage of field-level revenue, except in Louisiana, where severance taxes are volume-based. Production and property taxes decreased $17.4 million, or 47%, in the third quarter of 2019 compared to the third quarter of 2018, primarily due to decreased revenues in the Williston Basin as well as the Haynesville/Cotton Valley and Uinta Basin divestitures.
During the third quarter of 2019, production and property taxes decreased $0.22 per Boe, or 8%, compared to the third quarter of 2018, but decreased 35% excluding the Haynesville/Cotton Valley and Uinta Basin divestitures. The 35% decrease was primarily due to a decrease in average field-level equivalent prices in the Permian and Williston basins.
Production and property taxes decreased $36.3 million, or 35%, in the first three quarters of 2019 compared to the first three quarters of 2018, primarily due to decreased revenues in the Williston Basin as well as the Haynesville/Cotton Valley and Uinta Basin divestitures.
During the first three quarters of 2019, production and property taxes increased $0.27 per Boe, or 10%, compared to the first three quarters of 2018, but decreased 21% excluding the Haynesville/Cotton Valley and Uinta Basin divestitures. The 21% decrease was due to a decrease in average field-level equivalent prices in the Permian and Williston basins, partially offset by higher ad valorem charges per Boe in the Permian Basin.
Depreciation, depletion and amortization (DD&A). DD&A expense decreased $90.7 million in the third quarter of 2019 compared to the third quarter of 2018, primarily in the Williston Basin due to decreased production and a lower rate, as well as the Haynesville/Cotton Valley and Uinta Basin divestitures. The decreased DD&A rate in the Williston Basin was driven by a 2018 impairment. This decrease was partially offset by increased DD&A in the Permian Basin due to increased volumes and a slightly higher DD&A rate.
DD&A expense decreased $278.1 million in the first three quarters of 2019 compared to the first three quarters of 2018, primarily in the Williston Basin due to a lower DD&A rate and decreased production, as well as the Haynesville/Cotton Valley and Uinta Basin divestitures. The decreased DD&A rate in the Williston Basin was driven by a 2018 impairment. This decrease was partially offset by increased DD&A in the Permian Basin due to increased volumes and a slightly higher DD&A rate.
Impairment expense. During the third quarter of 2019 and 2018, there were no impairment charges.
During the first three quarters of 2019, QEP recorded impairment charges of $5.0 million, which related to impairment of an office building operating lease. During the first three quarters of 2018, QEP recorded impairment charges of $404.4 million, of which $402.8 million of proved and unproved properties impairment was triggered by the Uinta Basin Divestiture and $1.6 million was related to expiring leaseholds on unproved properties and impairment of proved properties related to a divestiture in the Other Northern area.
General and administrative (G&A) expense. During the third quarter of 2019, G&A expense decreased $18.7 million, or 39%, compared to the third quarter of 2018. During the third quarter of 2019 and 2018, QEP incurred $10.0 million and $14.2 million, respectively, in costs associated with the implementation of our strategic initiatives, of which $10.4 million and $12.8 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 these costs, G&A expense decreased by $14.4 million, or 42%, primarily due to $12.7 million lower labor, benefits and other associated costs due to the reduction in our workforce and $3.2 million in lower legal and outside service costs, partially offset by a $2.2 million decrease in overhead recoveries, primarily associated with our Haynesville/Cotton Valley and Uinta Basin divestitures.
During the first three quarters of 2019, G&A expense decreased $39.8 million, or 24%, compared to the first three quarters of 2018. During the first three quarters of 2019 and 2018, QEP incurred $43.2 million and $36.7 million, respectively, in costs associated with the implementation of our strategic initiatives, of which $36.7 million and $30.2 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 these costs, G&A expense decreased by $46.3 million, or 36%, primarily due to $41.8 million lower labor, benefits and other associated costs as of a result of the reduction in our workforce and $7.7 million in lower legal and outside service costs, partially offset by a $7.2 million decrease in overhead recoveries, primarily associated with our Haynesville/Cotton Valley and Uinta Basin divestitures.
Net gain (loss) from asset sales, inclusive of restructuring costs. During the third quarter of 2019, QEP recognized a loss on the sale of assets of $2.1 million, primarily related to a $2.7 million loss on the sale of the corporate aircraft, partially offset by a $0.9 million gain related to the divestiture of properties outside our main operating areas. During the third quarter of 2018, QEP recognized a gain on the sale of assets of $27.1 million primarily related to a net pre-tax gain on sale of $39.1 million related to the divestiture of properties outside our main operating areas and an additional pre-tax gain on sale of $0.4 million related to the sale of our Pinedale assets, partially offset by a pre-tax loss of $12.4 million related to the Uinta Basin Divestiture (refer to the Impairment expense discussion above for impairment charges related to the Uinta Basin Divestiture), which included $3.6 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).
During the first three quarters of 2019, QEP recognized a gain on the sale of assets of $2.5 million primarily related to the $3.5 million net gain from the divestiture of properties, partially offset by the loss on the sale of the corporate aircraft and a net pre-tax loss on sale of $1.0 million related to our Haynesville Divestiture, which included $1.4 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). During the first three quarters of 2018, QEP recognized a gain on the sale of assets of $26.7 million related to the divestiture of properties outside our main operating area and an additional pre-tax gain on sale of $1.2 million related to the sale of our Pinedale assets, partially offset by a pre-tax loss of $12.4 million related to the Uinta Basin Divestiture (refer to the Impairment expense discussion above for impairment charges related to the Uinta Basin Divestiture), which included $5.5 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 third quarter of 2019, gains on commodity derivative contracts were $87.4 million, of which $92.3 million were unrealized gains and $4.9 million were realized losses on settled derivative contracts. During the third quarter of 2018, losses on commodity derivative contracts were $108.0 million, of which $63.7 million were unrealized losses, $38.4 million were realized losses on derivative contracts related to production contracts and $5.9 million were unrealized losses related to the Uinta Basin Divestiture (refer to Note 7 – Derivative Contracts, in Item I of Part I of the Quarterly Report on Form 10-Q for more information).
During the first three quarters of 2019, losses on commodity derivative contracts were $55.8 million, of which $30.8 million were unrealized losses, $26.8 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). During the first three quarters of 2018, losses on commodity derivative contracts were $240.3 million, of which $127.1 million were realized losses on derivative contracts related to production and storage contracts, $107.3 million were unrealized losses and $5.9 million were unrealized losses related to the Uinta Basin Divestiture (refer to Note 7 – Derivative Contracts, in Item I of Part I of the Quarterly Report on Form 10-Q for more information).
Interest expense. Interest expense decreased $5.9 million, or 15%, during the third quarter of 2019 compared to the third quarter of 2018. The decrease during the third quarter of 2019 was primarily related to decreased borrowings under the credit facility.
Interest expense decreased $11.9 million, or 11%, during the first three quarters of 2019 compared to the first three quarters of 2018. The decrease during the first three quarters of 2019 was primarily related to decreased borrowings under the credit facility.
Income tax (provision) benefit. Income tax expense increased $24.1 million during the third quarter of 2019 compared to the third quarter of 2018. The increase in expense was the result of higher pre-tax income during the third quarter of 2019 compared to 2018. QEP’s effective federal and state income tax rate of 24.7% during the third quarter of 2019 compared to a rate of 25.5% during the third quarter of 2018 is primarily driven by the impact of discrete items recognized during the third quarter of 2018.
Income tax benefit decreased $61.9 million during the first three quarters of 2019 compared to the first three quarters of 2018. QEP's income tax benefit during the first three quarters of 2019 was impacted by a higher combined effective federal and state income tax rate of 130.8% during 2019 compared to a rate of 23.5% during the first three quarters of 2018. The increase in effective income tax rate was primarily driven by the re-measurement of QEP's deferred tax assets and liabilities at a lower blended state tax rate due to exiting the state of Louisiana as a result of the Haynesville Divestiture during the first three quarters of 2019.
LIQUIDITY AND CAPITAL RESOURCES
QEP strives to maintain sufficient liquidity to ensure financial flexibility, withstand commodity price volatility and fund its development projects, operations, capital expenditures, debt maturities, interest expense and quarterly dividends. 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. The Company expects that cash flows from its operating activities, cash on hand and borrowings under its revolving credit facility will be sufficient to fund its operations, capital expenditures, interest expense, debt maturities and quarterly dividends during the next 12 months and the foreseeable future. In August 2019, QEP's Board of Directors approved the reinstatement of a quarterly cash dividend of $0.02 per share of common stock. The third quarter 2019 dividend of $4.8 million was paid in September 2019.
During the nine months ended September 30, 2019, QEP closed the Haynesville Divestiture for net cash proceeds of $633.9 million. QEP used the proceeds to repay the outstanding balance on its revolving credit facility and for general corporate purposes.
As of September 30, 2019, the Company had $92.4 million in cash and cash equivalents, no borrowings under its revolving credit facility and $2.9 million in letters of credit outstanding. The Company estimates that as of September 30, 2019, it could
incur additional indebtedness of $307.9 million and be in compliance with the covenants contained in its revolving credit facility. To the extent actual operating results, realized commodity prices or uses of cash differ from the Company's assumptions, QEP's ability to incur additional indebtedness and liquidity could be adversely affected.
Credit Facility
QEP's unsecured revolving credit facility, which matures, subject to satisfaction of certain conditions, in September 2022, provides for loan commitments of $1.25 billion. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The credit agreement governing QEP's credit facility 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 net funded debt to capitalization ratio that may not exceed 60%, (ii) a leverage ratio under which net funded debt may not exceed 3.75 times consolidated EBITDA (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 funded debt by 1.40 times through December 31, 2019, and must exceed net funded debt by 1.50 times at any time on or after January 1, 2020. As of September 30, 2019 and December 31, 2018, QEP was in compliance with the covenants under the credit agreement.
During the nine months ended September 30, 2019, QEP's weighted-average interest rate on borrowings from its credit facility was 4.73%. As of September 30, 2019, QEP had no borrowings outstanding and $2.9 million in letters of credit outstanding under the credit facility. As of December 31, 2018, QEP had $430.0 million of borrowings outstanding and $0.3 million in letters of credit outstanding under the credit facility. As of October 18, 2019, QEP had no borrowings outstanding and had $2.9 million in letters of credit outstanding under the credit facility and was in compliance with the covenants under the credit agreement.
Senior Notes
The Company's senior notes outstanding as of September 30, 2019, totaled $2,099.3 million principal amount and are comprised of five issuances as follows:
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$51.7 million 6.80% Senior Notes due March 2020;
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•
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$397.6 million 6.875% Senior Notes due March 2021;
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•
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$500.0 million 5.375% Senior Notes due October 2022;
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•
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$650.0 million 5.25% Senior Notes due May 2023; and
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•
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$500.0 million 5.625% Senior Notes due March 2026.
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On October 23, 2019, the Company issued a notice to holders of its outstanding 6.80% Senior Notes due March 1, 2020, of the Company’s intent to redeem all of the outstanding notes on November 22, 2019. The Company expects that the redemption will decrease the "Current portion of long term debt" on the Condensed Consolidated Balance Sheets by $51.7 million and expects to incur a loss on early extinguishment of debt of approximately $0.7 million in connection with the redemption of the Senior Notes.
Cash Flow from Operating Activities
Cash flows from operating activities are primarily affected by oil and condensate, gas and NGL production volumes and commodity prices (including the effects of settlements of the Company's derivative contracts) and by changes in working capital. QEP typically enters into commodity derivative transactions covering a substantial, but varying, portion of its anticipated future oil and condensate production for the next 12 to 24 months.
Net cash provided by (used in) operating activities is presented below:
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Nine Months Ended September 30,
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2019
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2018
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Change
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(in millions)
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Net income (loss)
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$
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13.1
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$
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(382.3
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)
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$
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395.4
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Non-cash adjustments to net income (loss)
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383.2
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1,071.8
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(688.6
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)
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Changes in operating assets and liabilities
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(54.3
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)
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(14.6
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)
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(39.7
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)
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Net cash provided by (used in) operating activities
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$
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342.0
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$
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674.9
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$
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(332.9
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)
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Net cash provided by operating activities was $342.0 million during the first three quarters of 2019, which included $13.1 million of net income, $383.2 million of non-cash adjustments to net income and $54.3 million in changes in operating assets and liabilities. Non-cash adjustments to net income of $383.2 million primarily included DD&A expense of $395.5 million, $29.0 million of unrealized losses on derivative contracts and $16.2 million of non-cash share-based compensation expense, partially offset by $61.2 million of deferred income taxes benefit.
The decrease in changes in operating assets and liabilities of $54.3 million primarily resulted from decreases in accounts payable and accrued expenses of $55.2 million, other long-term liabilities of $9.8 million and accrued production and property taxes of $6.3 million, partially offset by a decrease in inventory of $10.6 million, decrease in prepaid expenses and other current assets of $2.7 million and an increase in operating leases of $2.7 million.
Net cash provided by operating activities was $674.9 million during the first three quarters of 2018, which included $382.3 million of net loss, $1,071.8 million of non-cash adjustments to the net loss and $14.6 million in changes in operating assets and liabilities. Non-cash adjustments to the net loss of $1,071.8 million primarily included DD&A expense of $673.6 million, $404.4 million of impairment expense, $113.2 million of unrealized losses on derivative contracts and $24.0 million of non-cash share-based compensation expense, partially offset by $119.6 million of deferred income tax benefit.
The decrease in changes in operating assets and liabilities of $14.6 million primarily resulted from an increase in accounts receivable of $49.8 million, partially offset by an increase in accounts payable and accrued expenses of $11.8 million and a decrease in other assets of $18.8 million.
Cash Flow from Investing Activities
A comparison of capital expenditures for the first three quarters of 2019 and 2018, are presented in the table below:
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Nine Months Ended September 30,
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2019
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2018
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Change
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(in millions)
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Property acquisitions
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$
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3.6
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$
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48.3
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$
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(44.7
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)
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Property, plant and equipment capital expenditures
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466.0
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988.2
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(522.2
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)
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Total accrued capital expenditures
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469.6
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1,036.5
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(566.9
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)
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Change in accruals and other non-cash adjustments
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(0.8
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)
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43.9
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(44.7
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)
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Total cash capital expenditures
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$
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468.8
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$
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1,080.4
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$
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(611.6
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)
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In the first three quarters of 2019, on an accrual basis, the Company invested $466.0 million on property, plant and equipment capital expenditures (which excludes property acquisitions), a decrease of $522.2 million compared to the first three quarters of 2018. In the first three quarters of 2019, QEP's primary capital expenditures included $396.5 million in the Permian Basin (including midstream infrastructure of $38.9 million, primarily related to oil and gas gathering and water handling) and $70.3 million in the Williston Basin.
In the first three quarters of 2018, on an accrual basis, the Company invested $988.2 million on property, plant and equipment capital expenditures (which excludes property acquisitions). QEP's significant capital expenditures included $689.7 million in the Permian Basin (including midstream infrastructure of $58.0 million, primarily related to oil and gas gathering and water handling), $165.1 million in the Williston Basin, $124.7 million in Haynesville/Cotton Valley (including midstream infrastructure of $7.5 million, primarily related to gas gathering) and $5.1 million in the Uinta Basin. In addition, in the first three quarters of 2018, QEP acquired various oil and gas properties, primarily proved and unproved leasehold acreage in the Permian Basin for an aggregate purchase price of $48.3 million, of which $37.6 million was related to the 2017 Permian Basin Acquisition.
The mid-point of our 2019 forecasted capital expenditures (excluding property acquisitions) is $574.5 million. QEP intends to fund capital expenditures (excluding property acquisitions) with cash flow from operating activities, cash on hand and borrowings under the credit facility. The aggregate levels of capital expenditures for 2019 and the allocation of those expenditures are dependent on a variety of factors, including drilling results, oil, gas and NGL prices, industry conditions, the extent to which properties or working interests are acquired, the availability of capital resources to fund the expenditures and changes in management's business assessments as to where QEP's capital can be most profitably deployed. 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 three quarters of 2019, net cash used in financing activities was $455.7 million compared to net cash provided by financing activities of $191.8 million in the first three quarters of 2018. During the first three quarters of 2019, QEP made repayments on its credit facility of $486.0 million, had borrowings from the credit facility of $56.0 million and paid a quarterly dividend payment of $4.8 million. In addition, QEP had treasury stock repurchases of $7.0 million related to the settlement of income tax and related benefit withholding obligations arising from the vesting of restricted share grants. During the first three quarters of 2019, QEP had a decrease in checks outstanding in excess of cash balances of $13.9 million.
During the first three quarters of 2018, QEP had borrowings from its credit facility of $2,616.0 million and repayments on its credit facility of $2,329.5 million. In addition, QEP used $58.4 million of cash to repurchase common stock under the Company's share repurchase program and had treasury stock repurchases of $7.8 million related to the settlement of income tax and related benefit withholding obligations arising from the vesting of restricted share grants. QEP also had a decrease in checks outstanding in excess of cash balances of $28.7 million.
As of September 30, 2019, the total principal amount of long-term debt was $2,081.1 million, of which $2,099.3 million was senior notes and $18.2 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. At September 30, 2019, 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 2018 Annual Report on Form 10-K.
Contractual Cash Obligations and Other Commitments
We have various contractual obligations in the normal course of our operations and financing activities. The Haynesville Divestiture resulted in a $195.4 million reduction in contractual cash obligations and other commitments subsequent to December 31, 2018, primarily related to firm transportation agreements and asset retirement obligations. There have been no other material changes to our contractual obligations from those disclosed in our 2018 Annual Report on Form 10-K.