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, 2017
(
2017
Form 10-K) and analyzes the changes in the results of operations between the
three and nine months ended
September 30, 2018
and
2017
. 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
2017
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 Louisiana) 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 2018, QEP's Board of Directors unanimously approved certain strategic and financial initiatives (Strategic Initiatives), including plans to market its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley and focus its activities in the Permian Basin. The Company executed a purchase and sale agreement to sell its Uinta Basin assets in early July 2018 and closed on the sale of the Uinta Basin assets in September 2018. Refer to discussion of the Uinta Basin Divestiture below under Acquisitions and Divestitures. Additionally, the Company is engaged in discussions with potential buyers regarding a transaction involving its Haynesville/Cotton Valley assets. On November 6, 2018, the Company's wholly owned subsidiary, QEP Energy Company, entered into a definitive agreement to sell its assets in the Williston Basin for a purchase price of up to
$1,725.0 million
, subject to purchase price adjustments which may be material (the Williston Basin Divestiture). The purchase price is comprised of
$1,650.0 million
in cash and contractual rights to receive up to
$50.0 million
and
$25.0 million
in the buyer's common stock if the daily volume weighted average trading price of the buyer's common stock for 10 out of 20 consecutive trading days is at or above
$12.00
per share and
$15.00
per share, respectively. QEP shall be entitled to the equity consideration if the share price thresholds are met at any time during the five year period following closing of the transaction. The transaction is subject to certain conditions, including, but not limited to, approval of buyer's shareholder and regulatory approvals and is expected to close late in the first quarter or early in the second quarter of 2019. At September 30, 2018, the Williston Basin assets were classified as held and used as the assets did not meet the held for sale criteria. Beginning in the fourth quarter of 2018, the assets and liabilities of the Williston Basin will be classified as held for sale in our Consolidated Balance Sheets for all comparative periods presented. As a part of the Strategic Initiatives, QEP has incurred or expects to incur costs associated with contractual termination benefits including severance and accelerated vesting of share-based compensation. Refer to
Note 3 – Acquisitions and Divestitures
and
Note 8 – Restructuring
, in Item I of Part I of this Quarterly Report on Form 10-Q for additional information.
Since the beginning of 2014, the Company has made approximately
$2.5 billion
of acquisitions of properties in the Permian Basin and spent approximately
40%
of its capital expenditures (excluding property acquisitions) on its properties in the Permian Basin. In
2018
, the Company plans to spend approximately
70%
of total planned capital expenditures to develop the Permian Basin.
Outlook
The Company continues to focus on reducing its operating costs and per well drilling costs and managing its liquidity as it executes on its plan to transition from a natural gas weighted company to a pure play Permian Basin company. We believe our balance sheet and sufficient liquidity will allow us to grow oil and condensate production in the Permian Basin and achieve our Strategic Initiatives.
Based on current commodity prices, we expect to be able to fund our planned capital program for the remainder of 2018 with cash flow from operating activities and borrowings under our credit facility. Our total capital expenditures (excluding property acquisitions) for
2018
are expected to be approximately
$1,165.0 million
, a
decrease
of approximately
4%
from 2017 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 may adjust our capital investment program based on such evaluations. See "Cash Flow from Investing Activities" for further discussion of our capital expenditures.
Acquisitions and Divestitures
While we believe our extensive inventory of identified drilling locations provides a solid base for growth in production and reserves, we will continue to evaluate and acquire properties in the Permian Basin to add additional development opportunities and facilitate the drilling of long lateral wells.
Acquisitions
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
, subject to post-closing purchase price adjustments. 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 Permian Basin Acquisition on substantially the same terms and conditions as the 2017 Permian Basin Acquisition.
In the fourth quarter of 2017, QEP acquired additional oil and gas properties in the Permian Basin (the 2017 Permian Basin Acquisition) for an aggregate purchase price of
$720.7 million
, subject to post-closing purchase price adjustments. The 2017 Permian Basin Acquisition consists of approximately
15,100
acres, mainly in Martin County, Texas, which are held by production from existing vertical wells. QEP structured the transaction as a like-kind exchange under Section 1031 of the Internal Revenue Service Code and funded the purchase price with the proceeds from the sale of QEP's Pinedale assets.
During the
nine months ended
September 30, 2017
, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage and additional surface acreage in the Permian Basin, for an aggregate purchase price of
$94.5 million
. In conjunction with these acquisitions, the Company recorded
$5.3 million
of goodwill, which was subsequently impaired in 2017.
Divestitures
In early 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
, subject to post-closing purchase price adjustments (the Uinta Basin Divestiture). During the
nine months ended
September 30, 2018
, QEP recorded a pre-tax
loss
of
$12.4 million
related to the Uinta Basin Divestiture, which included
$5.5 million
related to estimated restructuring costs recorded on the Condensed Consolidated Statements of Operations within "Net gain (loss) from asset sales, inclusive of restructuring costs". In conjunction with the Uinta Basin Divestiture, QEP recorded
$402.8 million
of proved and unproved properties impairment during the
nine months ended
September 30, 2018
. Refer to
Note 1 – Basis of Presentation
,
Note 3 – Acquisitions and Divestitures
and
Note 8 – Restructuring
, in Item I of Part 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
resulting in a net pre-tax
gain
on sale of
$37.9 million
related to the divestiture of properties outside our main operating areas.
In September 2017, QEP closed on the Pinedale Divestiture for net cash proceeds (after purchase price adjustments) of
$718.2 million
. During the
nine months ended
September 30, 2018
, QEP recorded a pre-tax
gain
on sale of
$1.2 million
, due to post-closing purchase price adjustments, which was recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations. During the year ended
December 31, 2017
, QEP recorded a pre-tax
gain
on sale of
$180.4 million
, which was recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations. In connection with the Pinedale Divestiture, QEP agreed to reimburse the buyer for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed
$45.0 million
. As of
September 30, 2018
, the remaining liability associated with estimated future payments for this commitment was
$23.0 million
.
In addition to the Pinedale Divestiture, during the
nine months ended
September 30, 2017
, QEP received net cash proceeds of
$69.7 million
, resulting in a net pre-tax
gain
on sale of
$26.4 million
, primarily related to the divestiture of certain properties in the Other Northern area.
Financial and Operating Highlights
During the
three months ended
September 30, 2018
, QEP:
|
|
•
|
Closed the Uinta Basin Divestiture, for net cash proceeds of
$153.0 million
;
|
|
|
•
|
Delivered record oil and condensate production of
6.6
MMbbls, a
38%
increase
over
2017
volumes;
|
|
|
•
|
Increased oil and condensate production in the Permian Basin by
108%
to a record
3.5
MMbbls;
|
|
|
•
|
Increased gas production in Haynesville/Cotton Valley to
27.4
Bcf, a
38%
increase
over
2017
volumes, primarily due to successful refracturing and drilling programs;
|
|
|
•
|
Reported net realized oil price of
$56.38
per bbl, an
18%
increase
over
2017
;
|
|
|
•
|
Generated net
income
of
$7.3 million
or
$0.03
per diluted share; and
|
|
|
•
|
Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of
$326.2 million
, a
69%
increase
over
2017
.
|
During the
nine months ended
September 30, 2018
, QEP:
|
|
•
|
Closed the Uinta Basin Divestiture, for net cash proceeds of
$153.0 million
;
|
|
|
•
|
Delivered oil and condensate production of
18.2
MMbbls, a
26%
increase
over
2017
volumes;
|
|
|
•
|
Increased oil and condensate production in the Permian Basin by
115%
to a record
8.9
MMbbls;
|
|
|
•
|
Increased gas production in Haynesville/Cotton Valley to
81.6
Bcf, a
67%
increase
over
2017
volumes, primarily due to successful refracturing and drilling programs;
|
|
|
•
|
Reported net realized oil price of
$54.30
per bbl, a
15%
increase
over
2017
;
|
|
|
•
|
Repurchased and retired
6.2 million
shares of the Company's common stock outstanding for
$58.4 million
;
|
|
|
•
|
Generated a net
loss
of
$382.3 million
, or
$1.60
per diluted share; and
|
|
|
•
|
Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of
$780.7 million
, a
44%
increase
over
2017
.
|
Factors Affecting Results of Operations
Supply, Demand, Market Risk and their Impact on Oil and Gas Prices
Oil and gas prices are affected by many factors outside of our control, including changes in market 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 and gas prices have been affected by supply growth, particularly in U.S. oil and gas production, 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, gas and NGL 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, our 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 and gas 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 $107.95 per barrel in June 2014. The Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $8.15 per MMBtu in February 2014. If prices of oil, gas or NGL decline to early 2016 levels or further, our operations, financial condition and level of expenditures for the development of our oil and gas 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 economic issues in South America, Asia, Europe, the Middle East, and Africa; 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, 2018
, QEP forecasted its
2018
annual production to be approximately
51.5
MMboe and had approximately
64%
of its forecasted oil production and
71%
of its forecasted gas 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 properties 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 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. In addition, the signing of a purchase and sale agreement could also trigger 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, 2018
, QEP recorded impairment charges of
$404.4 million
, of which
$402.8 million
of proved and unproved properties impairment related to the Uinta Basin Divestiture. Additionally, QEP recorded
$1.6 million
related to expiring leaseholds on unproved properties and impairment of proved properties for a divestiture in the Other Northern area.
During the
nine months ended
September 30, 2017
, QEP recorded an impairment charge of
$28.4 million
, which was primarily related to unproved leasehold acreage in the Central Basin Platform.
Triggered by signing the Williston Basin purchase and sale agreement in November 2018, the Company expects to incur proved and unproved impairment charges, in aggregate, of approximately
$1.2 billion
, of which approximately
$1.1 billion
is expected to be incurred in the fourth quarter 2018, and the remaining expense to be incurred in subsequent quarters through the estimated closing date, resulting in a reduction of the approximate net book value to fair value at each reporting period. The estimated fair value at each reporting period will be determined using the fair value of the equity consideration and the cash purchase price adjusted for estimated purchase price adjustments from the effective date of July 2018 through the estimated closing date of the transaction, discounted at the Company's weighted average cost of capital, less cost to sell the assets. The impairment charges will be determined using the fair value less cost to sell, compared to the net book value of the assets to be sold. The actual amount of impairment incurred will depend on a variety of factors including, but not limited to, the stock price of the buyer's common stock, revenues, operating expenses and capital costs incurred subsequent to the effective date.
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. In certain of our producing areas, 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. As a result, 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 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/or capital expenditures for a particular reporting period, including, but not limited to those described in
Note 10 – 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
2017
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, capitalized exploratory well costs, impairment of long-lived assets, asset retirement obligations, revenue recognition, litigation and other contingencies, environmental obligations, 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 at
September 30, 2018
:
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|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
Non-operated
|
|
Drilling
|
|
Drilling
|
|
Waiting on completion
|
|
Drilling
|
|
Waiting on completion
|
|
Rigs
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Uinta Basin
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other Northern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
(1)
|
4
|
|
|
21
|
|
|
21.0
|
|
|
27
|
|
|
26.7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Haynesville/Cotton Valley
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
0.0
|
|
|
9
|
|
|
0.5
|
|
Other Southern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
____________________________
|
|
(1)
|
The gross operated drilling well count in the Permian Basin includes 13 wells for which surface casing has been set, but as of
September 30, 2018
, did not have a rig drilling.
|
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
27
gross operated wells waiting on completion as of
September 30, 2018
.
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, 2018
:
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|
Operated Put on Production
|
|
Non-operated Put on Production
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
September 30, 2018
|
|
September 30, 2018
|
|
September 30, 2018
|
|
September 30, 2018
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
—
|
|
|
—
|
|
|
11
|
|
|
10.1
|
|
|
11
|
|
|
0.1
|
|
|
13
|
|
|
0.2
|
|
Uinta Basin
|
—
|
|
|
—
|
|
|
2
|
|
|
2.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other Northern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
21
|
|
|
21.0
|
|
|
89
|
|
|
88.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Haynesville/Cotton Valley
|
1
|
|
|
1.0
|
|
|
4
|
|
|
4.0
|
|
|
1
|
|
|
0.0
|
|
|
10
|
|
|
0.5
|
|
Other Southern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
The following table presents the number of operated wells in the process of being drilled or waiting on completion at
September 30, 2018
and operated wells completed and turned to sales (put on production) for the
nine months ended
September 30, 2018
:
|
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
|
Williston Basin
|
|
Haynesville/Cotton Valley
|
|
Uinta Basin
|
|
As of September 30, 2018
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
Well Progress
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling
|
21
|
|
|
21.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At total depth - under drilling rig
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Waiting to be completed
|
16
|
|
|
16.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Undergoing completion
|
4
|
|
|
3.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Completed, awaiting production
|
7
|
|
|
6.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Waiting on completion
|
27
|
|
|
26.7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Put on production
|
89
|
|
|
88.1
|
|
|
11
|
|
|
10.1
|
|
|
4
|
|
|
4.0
|
|
|
2
|
|
|
2.0
|
|
RESULTS OF OPERATIONS
Net Income
QEP generated net
income
during the
third quarter
of
2018
of
$7.3 million
, or
$0.03
per diluted share, compared to a net
loss
of
$3.3 million
, or
$0.01
per diluted share, in the
third quarter
of
2017
. QEP's net
income
was primarily driven by a
$198.1 million
increase
in oil and condensate sales due to a
38%
increase
in oil and condensate production and an
18%
increase
in average net realized oil prices in the
third quarter
of
2018
compared to the
third quarter
of
2017
. These increases were partially offset by a
$158.3 million
decrease
in gain from asset sales, inclusive of restructuring costs due to the gain on sale from the Pinedale Divestiture in 2017.
QEP generated a net
loss
during the
first three quarters
of
2018
of
$382.3 million
or
$1.60
per diluted share, compared to net
income
of
$119.0 million
or
$0.49
per diluted share, in the
first three quarters
of
2017
. QEP's net
loss
was primarily driven by a
$403.6 million
increase
in realized and unrealized derivative
losses
, a
$376.0 million
increase
in impairment expense, a
$113.4 million
increase
in depreciation, depletion and amortization and a
$55.9 million
increase
in general and administrative expense. These increases to the net
loss
were partially offset by a
$469.6 million
increase
in oil and condensate sales due to a
26%
increase in oil and condensate production and a
15%
increase
in average net realized oil prices and a
$68.5 million
decrease
in adjusted transportation and processing costs (a non-GAAP measure defined and reconciled in Operating Expenses below) in the
first three quarters
of
2018
compared to the
first three quarters
of
2017
due to the Pinedale Divestiture and Uinta Basin Divestiture.
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) (a 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
(in millions)
|
Net income (loss)
|
$
|
7.3
|
|
|
$
|
(3.3
|
)
|
|
$
|
(382.3
|
)
|
|
$
|
119.0
|
|
Interest expense
|
38.7
|
|
|
34.4
|
|
|
111.9
|
|
|
103.1
|
|
Interest and other (income) expense
|
0.3
|
|
|
(0.1
|
)
|
|
4.1
|
|
|
(2.5
|
)
|
Income tax provision (benefit)
|
2.5
|
|
|
(3.2
|
)
|
|
(117.6
|
)
|
|
69.7
|
|
Depreciation, depletion and amortization
|
234.9
|
|
|
176.9
|
|
|
673.6
|
|
|
560.2
|
|
Unrealized (gains) losses on derivative contracts
|
69.6
|
|
|
116.0
|
|
|
113.2
|
|
|
(161.6
|
)
|
Exploration expenses
|
—
|
|
|
21.3
|
|
|
0.1
|
|
|
21.7
|
|
Net (gain) loss from asset sales, inclusive of restructuring costs
|
(27.1
|
)
|
|
(185.4
|
)
|
|
(26.7
|
)
|
|
(205.2
|
)
|
Impairment
|
—
|
|
|
28.3
|
|
|
404.4
|
|
|
28.4
|
|
Other
(1)
|
—
|
|
|
8.2
|
|
|
—
|
|
|
8.2
|
|
Adjusted EBITDA
|
$
|
326.2
|
|
|
$
|
193.1
|
|
|
$
|
780.7
|
|
|
$
|
541.0
|
|
____________________________
|
|
(1)
|
Reflects legal expenses and loss contingencies incurred during the
three and nine months ended
September 30, 2017
. The Company believes that these amounts do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded these amounts from the calculation of Adjusted EBITDA.
|
In the
third quarter
of 2018, Adjusted EBITDA
increase
d to
$326.2 million
compared to
$193.1 million
in the
third quarter
of
2017
, primarily due to a
38%
increase
in oil and condensate production, mainly in the Permian Basin, an
18%
increase
in average net realized oil prices and a
38%
increase
in gas production in Haynesville/Cotton Valley, partially offset by a
$50.1 million
increase
in realized derivative
losses
, a
$29.0 million
decrease
in gas sales primarily due to the Pinedale Divestiture and a
1%
reduction in average net realized gas price.
In the
first three quarters
of
2018
, Adjusted EBITDA
increase
d to
$780.7 million
compared to
$541.0 million
in the
first three quarters
of
2017
, primarily due to a
26%
increase
in oil and condensate production, mainly in the Permian Basin, a
15%
increase
in average net realized oil prices, a
67%
increase
in gas production in Haynesville/Cotton Valley and a
$128.8 million
decrease
in realized derivative
losses
, partially offset by a
$97.9 million
decrease
in gas sales primarily due to the Pinedale Divestiture.
Revenue
The following table presents our revenues disaggregated by revenue source.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
September 30,
|
|
September 30,
|
|
2018
|
|
2017
(1)
|
|
Change
|
|
2018
|
|
2017
(1)
|
|
Change
|
|
(in millions)
|
Oil and condensate sales
|
$
|
416.1
|
|
|
$
|
218.0
|
|
|
$
|
198.1
|
|
|
$
|
1,125.3
|
|
|
$
|
655.7
|
|
|
$
|
469.6
|
|
Gas sales
|
101.7
|
|
|
130.7
|
|
|
(29.0
|
)
|
|
301.5
|
|
|
399.4
|
|
|
(97.9
|
)
|
NGL sales
|
42.0
|
|
|
32.2
|
|
|
9.8
|
|
|
88.2
|
|
|
84.0
|
|
|
4.2
|
|
Oil and condensate, gas and NGL sales, as adjusted
(2)
|
559.8
|
|
|
380.9
|
|
|
$
|
178.9
|
|
|
1,515.0
|
|
|
1,139.1
|
|
|
375.9
|
|
Transportation and processing costs included in revenue
(3)
|
(15.8
|
)
|
|
—
|
|
|
(15.8
|
)
|
|
(40.9
|
)
|
|
—
|
|
|
(40.9
|
)
|
Oil and condensate, gas and NGL sales, as presented
|
$
|
544.0
|
|
|
$
|
380.9
|
|
|
$
|
163.1
|
|
|
$
|
1,474.1
|
|
|
$
|
1,139.1
|
|
|
$
|
335.0
|
|
____________________________
|
|
(1)
|
Prior period amounts have not been adjusted under the modified retrospective method for the new revenue recognition rule. Refer to
Note 2 – Revenue
in Part 1, Item I of this Quarterly Report on Form 10-Q.
|
|
|
(2)
|
Above is a reconciliation of Oil and condensate, gas and NGL sales (a GAAP measure) as presented on the Condensed Consolidated Statements of Operations to Oil and condensate, gas and NGL sales, as adjusted (a non-GAAP measure). Oil and condensate, gas and NGL sales, as adjusted excludes transportation and processing costs that are included as part of "Oil and condensate, gas and NGL sales" on the Condensed Consolidated Statements of Operations. Management removes these costs from "Oil and condensate, gas and NGL sales" included on the Condensed Consolidated Statements of Operations 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 and is a more comparable measure to reported revenue of its peers. 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. Refer to
Note 2 – Revenue
in Part 1, Item I of this Quarterly Report on Form 10-Q.
|
|
|
(3)
|
Transportation and processing costs in the table above is not representative of total transportation and processing costs incurred. Refer to the Operating Expenses section below for a reconciliation of total transportation and processing costs.
|
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, 2018
, compared to the
three and nine months ended
September 30, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate
|
|
Gas
|
|
NGL
|
|
Total
|
|
(in millions)
|
Oil and condensate, gas and NGL sales, as adjusted
|
|
|
|
|
|
|
|
Three months ended September 30, 2017
|
$
|
218.0
|
|
|
$
|
130.7
|
|
|
$
|
32.2
|
|
|
$
|
380.9
|
|
Changes associated with volumes
(1)
|
82.0
|
|
|
(24.0
|
)
|
|
(2.1
|
)
|
|
55.9
|
|
Changes associated with prices
(2)
|
116.1
|
|
|
(5.0
|
)
|
|
11.9
|
|
|
123.0
|
|
Three months ended September 30, 2018
|
$
|
416.1
|
|
|
$
|
101.7
|
|
|
$
|
42.0
|
|
|
$
|
559.8
|
|
|
|
|
|
|
|
|
|
Oil and condensate, gas and NGL sales, as adjusted
|
|
|
|
|
|
|
|
Nine months ended September 30, 2017
|
$
|
655.7
|
|
|
$
|
399.4
|
|
|
$
|
84.0
|
|
|
$
|
1,139.1
|
|
Changes associated with volumes
(1)
|
173.4
|
|
|
(69.5
|
)
|
|
(15.0
|
)
|
|
88.9
|
|
Changes associated with prices
(2)
|
296.2
|
|
|
(28.4
|
)
|
|
19.2
|
|
|
287.0
|
|
Nine months ended September 30, 2018
|
$
|
1,125.3
|
|
|
$
|
301.5
|
|
|
$
|
88.2
|
|
|
$
|
1,515.0
|
|
____________________________
|
|
(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, 2018
, as compared to the
three and nine months ended
September 30, 2017
, by the average field-level price for the
three and nine months ended
September 30, 2017
.
|
|
|
(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, 2018
, as compared to the
three and nine months ended
September 30, 2017
, by the respective volumes for the
three and nine months ended
September 30, 2018
. 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,
|
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
Total production volumes (Mboe)
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
4,381.1
|
|
|
4,252.3
|
|
|
128.8
|
|
|
12,570.5
|
|
|
13,660.2
|
|
|
(1,089.7
|
)
|
Pinedale
|
—
|
|
|
3,010.8
|
|
|
(3,010.8
|
)
|
|
0.1
|
|
|
9,842.4
|
|
|
(9,842.3
|
)
|
Uinta Basin
|
606.0
|
|
|
905.3
|
|
|
(299.3
|
)
|
|
2,232.2
|
|
|
2,770.6
|
|
|
(538.4
|
)
|
Other Northern
|
63.1
|
|
|
278.1
|
|
|
(215.0
|
)
|
|
211.3
|
|
|
945.6
|
|
|
(734.3
|
)
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
4,792.5
|
|
|
2,351.3
|
|
|
2,441.2
|
|
|
11,591.6
|
|
|
5,672.9
|
|
|
5,918.7
|
|
Haynesville/Cotton Valley
|
4,552.8
|
|
|
3,321.2
|
|
|
1,231.6
|
|
|
13,604.6
|
|
|
8,160.2
|
|
|
5,444.4
|
|
Other Southern
|
4.5
|
|
|
5.1
|
|
|
(0.6
|
)
|
|
20.4
|
|
|
23.1
|
|
|
(2.7
|
)
|
Total production
|
14,400.0
|
|
|
14,124.1
|
|
|
275.9
|
|
|
40,230.7
|
|
|
41,075.0
|
|
|
(844.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equivalent prices (per Boe)
|
|
|
|
|
|
|
|
|
|
|
|
Average field-level equivalent price
|
$
|
38.87
|
|
|
$
|
26.97
|
|
|
$
|
11.90
|
|
|
$
|
37.66
|
|
|
$
|
27.73
|
|
|
$
|
9.93
|
|
Commodity derivative impact
|
(2.66
|
)
|
|
0.83
|
|
|
(3.49
|
)
|
|
(3.16
|
)
|
|
0.05
|
|
|
(3.21
|
)
|
Net realized equivalent price
|
$
|
36.21
|
|
|
$
|
27.80
|
|
|
$
|
8.41
|
|
|
$
|
34.50
|
|
|
$
|
27.78
|
|
|
$
|
6.72
|
|
Oil and Condensate Volumes and Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
Oil and condensate production volumes (Mbbl)
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
2,968.6
|
|
|
2,803.3
|
|
|
165.3
|
|
|
8,747.6
|
|
|
9,216.5
|
|
|
(468.9
|
)
|
Pinedale
|
—
|
|
|
124.0
|
|
|
(124.0
|
)
|
|
—
|
|
|
404.7
|
|
|
(404.7
|
)
|
Uinta Basin
|
124.7
|
|
|
169.7
|
|
|
(45.0
|
)
|
|
445.0
|
|
|
498.3
|
|
|
(53.3
|
)
|
Other Northern
|
19.8
|
|
|
30.0
|
|
|
(10.2
|
)
|
|
76.8
|
|
|
94.2
|
|
|
(17.4
|
)
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
3,525.7
|
|
|
1,692.8
|
|
|
1,832.9
|
|
|
8,892.0
|
|
|
4,144.1
|
|
|
4,747.9
|
|
Haynesville/Cotton Valley
|
1.9
|
|
|
6.8
|
|
|
(4.9
|
)
|
|
12.2
|
|
|
19.7
|
|
|
(7.5
|
)
|
Other Southern
|
(0.2
|
)
|
|
0.5
|
|
|
(0.7
|
)
|
|
8.5
|
|
|
2.6
|
|
|
5.9
|
|
Total production
|
6,640.5
|
|
|
4,827.1
|
|
|
1,813.4
|
|
|
18,182.1
|
|
|
14,380.1
|
|
|
3,802.0
|
|
Average field-level oil prices (per bbl)
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
$
|
68.06
|
|
|
$
|
44.63
|
|
|
$
|
23.43
|
|
|
$
|
64.80
|
|
|
$
|
45.07
|
|
|
$
|
19.73
|
|
Southern Region
|
$
|
57.88
|
|
|
$
|
46.13
|
|
|
$
|
11.75
|
|
|
$
|
58.87
|
|
|
$
|
46.88
|
|
|
$
|
11.99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average field-level price
|
$
|
62.65
|
|
|
$
|
45.16
|
|
|
$
|
17.49
|
|
|
$
|
61.89
|
|
|
$
|
45.60
|
|
|
$
|
16.29
|
|
Commodity derivative impact
|
(6.27
|
)
|
|
2.51
|
|
|
(8.78
|
)
|
|
(7.59
|
)
|
|
1.50
|
|
|
(9.09
|
)
|
Net realized price
|
$
|
56.38
|
|
|
$
|
47.67
|
|
|
$
|
8.71
|
|
|
$
|
54.30
|
|
|
$
|
47.10
|
|
|
$
|
7.20
|
|
Oil and condensate revenues
increase
d
$198.1 million
, or
91%
, in the
third quarter
of
2018
compared to the
third quarter
of
2017
, due to
higher
average field-level prices and
higher
oil and condensate production volumes. Average field-level oil prices
increase
d
39%
in the
third quarter
of
2018
compared to the
third quarter
of
2017
primarily driven by an
increase
in average NYMEX-WTI oil prices for the comparable periods, partially offset by a $4.02, or 133% increase, in the basis differential relative to the average NYMEX-WTI oil price in the
third quarter
of
2018
compared to the
third quarter
of
2017
. The
38%
increase
in production volumes was driven by increases in the Permian and Williston basins due to increased drilling activity as well as refracturing activity in the Williston Basin, partially offset by a loss of volumes as a result of the Pinedale Divestiture in September 2017 and the Uinta Basin Divestiture in early September 2018.
Oil and condensate revenues
increase
d
$469.6 million
, or
72%
, in the
first three quarters
of
2018
compared to the
first three quarters
of
2017
, due to
higher
average field-level prices and
higher
oil and condensate production volumes. Average field-level oil prices
increase
d
36%
in the
first three quarters
of
2018
compared to the
first three quarters
of
2017
primarily driven by an
increase
in average NYMEX-WTI oil prices for the comparable periods, partially offset by a $1.36, or 37% increase, in the basis differential relative to the average NYMEX-WTI oil price in the
third quarter
of
2018
compared to the
third quarter
of
2017
. The
26%
increase
in production volumes was driven by an increase in the Permian Basin due to increased drilling and completion activity, partially offset by a decrease in production in the Williston Basin and a loss of volumes from Pinedale as a result of the Pinedale Divestiture.
Gas Volumes and Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
Gas production volumes (Bcf)
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
4.4
|
|
|
3.7
|
|
|
0.7
|
|
|
11.6
|
|
|
11.8
|
|
|
(0.2
|
)
|
Pinedale
|
—
|
|
|
15.8
|
|
|
(15.8
|
)
|
|
—
|
|
|
51.9
|
|
|
(51.9
|
)
|
Uinta Basin
|
2.7
|
|
|
4.1
|
|
|
(1.4
|
)
|
|
10.1
|
|
|
12.9
|
|
|
(2.8
|
)
|
Other Northern
|
0.3
|
|
|
1.4
|
|
|
(1.1
|
)
|
|
0.8
|
|
|
5.0
|
|
|
(4.2
|
)
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
3.3
|
|
|
1.8
|
|
|
1.5
|
|
|
7.3
|
|
|
4.3
|
|
|
3.0
|
|
Haynesville/Cotton Valley
|
27.4
|
|
|
19.9
|
|
|
7.5
|
|
|
81.6
|
|
|
48.8
|
|
|
32.8
|
|
Other Southern
|
—
|
|
|
—
|
|
|
—
|
|
|
0.1
|
|
|
0.1
|
|
|
—
|
|
Total production
|
38.1
|
|
|
46.7
|
|
|
(8.6
|
)
|
|
111.5
|
|
|
134.8
|
|
|
(23.3
|
)
|
Average field-level gas prices (per Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
$
|
2.59
|
|
|
$
|
2.74
|
|
|
$
|
(0.15
|
)
|
|
$
|
2.52
|
|
|
$
|
2.95
|
|
|
$
|
(0.43
|
)
|
Southern Region
|
$
|
2.69
|
|
|
$
|
2.86
|
|
|
$
|
(0.17
|
)
|
|
$
|
2.75
|
|
|
$
|
2.97
|
|
|
$
|
(0.22
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Average field-level price
|
$
|
2.67
|
|
|
$
|
2.80
|
|
|
$
|
(0.13
|
)
|
|
$
|
2.71
|
|
|
$
|
2.96
|
|
|
$
|
(0.25
|
)
|
Commodity derivative impact
|
0.09
|
|
|
(0.01
|
)
|
|
0.10
|
|
|
0.10
|
|
|
(0.15
|
)
|
|
0.25
|
|
Net realized price
|
$
|
2.76
|
|
|
$
|
2.79
|
|
|
$
|
(0.03
|
)
|
|
$
|
2.81
|
|
|
$
|
2.81
|
|
|
$
|
—
|
|
Gas revenues
decrease
d
$29.0 million
, or
22%
, in the
third quarter
of
2018
compared to the
third quarter
of
2017
, due to
lower
gas production volumes and
lower
average field-level prices. Production volumes
decrease
d
18%
primarily due to the Pinedale Divestiture, the Uinta Basin Divestiture in early September 2018 and additional divestitures outside our main operating areas. These production
decrease
s were partially offset by increases in Haynesville/Cotton Valley and the Permian and Williston basins due to increased drilling and completion activity in early 2018 as well as the refracturing programs in Haynesville/Cotton Valley and Williston Basin. The production increase in the Permian Basin was partially offset by lower gas capture rates in the
third quarter
of
2018
compared to the
third quarter
of
2017
due to midstream infrastructure construction and well connection activities in the area. Average field-level gas prices
decrease
d
5%
in the
third quarter
of
2018
compared to the
third quarter
of
2017
, primarily driven by a decrease in average NYMEX-HH gas prices for the comparable periods.
Gas revenues
decrease
d
$97.9 million
, or
25%
, in the
first three quarters
of
2018
compared to the
first three quarters
of
2017
, due to
lower
gas production volumes and
lower
average field-level prices. Production volumes
decrease
d
17%
in the
first three quarters
of
2018
compared to the
first three quarters
of
2017
, primarily due to the Pinedale Divestiture, the Uinta Basin Divestiture in early September 2018 and additional divestitures outside our main operating areas. These production
decrease
s were partially offset by increases in production in Haynesville/Cotton Valley and the Permian Basin. The
increase
in gas production in Haynesville/Cotton Valley was due to the refracturing and drilling programs. The increase in production in the Permian Basin was due to increased drilling and completion activity, partially offset by lower gas capture rates in the Permian Basin in the
first three quarters
of
2018
compared to the
first three quarters
of
2017
, due to midstream infrastructure construction and well connection activities in the area. Average field-level gas prices
decrease
d
8%
in the
first three quarters
of
2018
compared to the
first three quarters
of
2017
, primarily driven by a decrease in average NYMEX-HH gas prices for the comparable periods.
NGL Volumes and Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
NGL production volumes (Mbbl)
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
667.6
|
|
|
834.7
|
|
|
(167.1
|
)
|
|
1,885.7
|
|
|
2,480.6
|
|
|
(594.9
|
)
|
Pinedale
|
—
|
|
|
255.5
|
|
|
(255.5
|
)
|
|
—
|
|
|
779.5
|
|
|
(779.5
|
)
|
Uinta Basin
|
25.7
|
|
|
42.3
|
|
|
(16.6
|
)
|
|
96.9
|
|
|
117.3
|
|
|
(20.4
|
)
|
Other Northern
|
3.7
|
|
|
3.8
|
|
|
(0.1
|
)
|
|
9.4
|
|
|
12.0
|
|
|
(2.6
|
)
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
717.9
|
|
|
376.0
|
|
|
341.9
|
|
|
1,479.2
|
|
|
823.6
|
|
|
655.6
|
|
Haynesville/Cotton Valley
|
0.1
|
|
|
4.9
|
|
|
(4.8
|
)
|
|
0.4
|
|
|
13.6
|
|
|
(13.2
|
)
|
Other Southern
|
0.3
|
|
|
(1.1
|
)
|
|
1.4
|
|
|
0.9
|
|
|
(0.2
|
)
|
|
1.1
|
|
Total production
|
1,415.3
|
|
|
1,516.1
|
|
|
(100.8
|
)
|
|
3,472.5
|
|
|
4,226.4
|
|
|
(753.9
|
)
|
Average field-level NGL prices (per bbl)
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
$
|
29.55
|
|
|
$
|
21.89
|
|
|
$
|
7.66
|
|
|
$
|
25.32
|
|
|
$
|
20.52
|
|
|
$
|
4.80
|
|
Southern Region
|
$
|
29.74
|
|
|
$
|
19.43
|
|
|
$
|
10.31
|
|
|
$
|
25.49
|
|
|
$
|
17.35
|
|
|
$
|
8.14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average field-level price
|
$
|
29.65
|
|
|
$
|
21.28
|
|
|
$
|
8.37
|
|
|
$
|
25.39
|
|
|
$
|
19.89
|
|
|
$
|
5.50
|
|
Commodity derivative impact
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net realized price
|
$
|
29.65
|
|
|
$
|
21.28
|
|
|
$
|
8.37
|
|
|
$
|
25.39
|
|
|
$
|
19.89
|
|
|
$
|
5.50
|
|
NGL production volumes and revenues represent the sale of liquids derived from the processing of QEP's natural gas production. NGL revenues
increase
d
$9.8 million
, or
30%
, during the
third quarter
of
2018
compared to the
third quarter
of
2017
, due to
higher
average field-level prices, partially offset by
lower
NGL production volumes. The
39%
increase
in NGL prices during the
third quarter
of
2018
compared to the
third quarter
of
2017
was primarily driven by an increase in propane, ethane and other NGL component prices. The
increase
in price was partially offset by a
7%
decrease
in NGL production volumes. The decrease was primarily driven by a loss of volumes from Pinedale due to the Pinedale Divestiture and a production decrease in the Williston Basin due to declining gas volumes and lower ethane recovery in the
third quarter
of
2018
compared to the
third quarter
of
2017
. These production decreases were partially offset by an increase in production in the Permian Basin due to increased drilling and completion activity.
NGL revenues
increase
d
$4.2 million
, or
5%
, during the
first three quarters
of
2018
compared to the
first three quarters
of
2017
, due to
higher
average field-level prices, partially offset by
lower
NGL production volumes. The
28%
increase
in NGL prices during the
first three quarters
of
2018
compared to the
first three quarters
of
2017
was primarily driven by an increase in propane, ethane and other NGL component prices. The
increase
in price was partially offset by an
18%
decrease
in NGL production volumes primarily driven by a loss of volumes from Pinedale due to the Pinedale Divestiture and production decreases in the Williston Basin due to declining gas volumes and lower ethane recovery during the
first three quarters
of
2018
compared to the
first three quarters
of
2017
. These decreases were partially offset by an increase in production in the Permian Basin due to increased drilling and completion activity.
Resale Margin and Storage Activity
QEP purchases and resells oil and gas primarily to mitigate losses on unutilized capacity related to firm transportation commitments and storage activities. 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,
|
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
|
(in millions)
|
Purchased oil and gas sales
|
$
|
13.0
|
|
|
$
|
5.6
|
|
|
$
|
7.4
|
|
|
$
|
36.2
|
|
|
$
|
44.5
|
|
|
$
|
(8.3
|
)
|
Purchased oil and gas expense
|
(13.3
|
)
|
|
(6.9
|
)
|
|
(6.4
|
)
|
|
(38.6
|
)
|
|
(45.4
|
)
|
|
6.8
|
|
Realized gains (losses) on gas storage derivative contracts
|
—
|
|
|
—
|
|
|
—
|
|
|
0.3
|
|
|
(0.2
|
)
|
|
0.5
|
|
Resale margin
|
$
|
(0.3
|
)
|
|
$
|
(1.3
|
)
|
|
$
|
1.0
|
|
|
$
|
(2.1
|
)
|
|
$
|
(1.1
|
)
|
|
$
|
(1.0
|
)
|
Purchased oil and gas sales and expense
increase
d during the
third quarter
of
2018
compared to
third quarter
of
2017
, due to an increase in resale volumes to meet Northern Region gas transportation commitments retained in the various divestitures, partially offset by lower resale volumes needed to meet gas transportation commitments in the Southern Region due to increased production.
Purchased oil and gas sales and expense
decrease
d during the
first three quarters
of
2018
compared to
first three quarters
of
2017
, due to lower resale volumes following the sale of an underground gas storage facility in May 2018.
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,
|
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
|
(in millions)
|
Lease operating expense
|
$
|
64.6
|
|
|
$
|
76.2
|
|
|
$
|
(11.6
|
)
|
|
$
|
203.6
|
|
|
$
|
215.4
|
|
|
$
|
(11.8
|
)
|
Adjusted transportation and processing costs
(1)
|
43.8
|
|
|
60.2
|
|
|
(16.4
|
)
|
|
134.1
|
|
|
202.6
|
|
|
(68.5
|
)
|
Production and property taxes
|
37.4
|
|
|
28.5
|
|
|
8.9
|
|
|
103.9
|
|
|
86.1
|
|
|
17.8
|
|
Total production costs
|
$
|
145.8
|
|
|
$
|
164.9
|
|
|
$
|
(19.1
|
)
|
|
$
|
441.6
|
|
|
$
|
504.1
|
|
|
$
|
(62.5
|
)
|
|
(per Boe)
|
Lease operating expense
|
$
|
4.49
|
|
|
$
|
5.39
|
|
|
$
|
(0.90
|
)
|
|
$
|
5.06
|
|
|
$
|
5.24
|
|
|
$
|
(0.18
|
)
|
Adjusted transportation and processing costs
(1)
|
3.04
|
|
|
4.26
|
|
|
(1.22
|
)
|
|
3.34
|
|
|
4.93
|
|
|
(1.59
|
)
|
Production and property taxes
|
2.60
|
|
|
2.02
|
|
|
0.58
|
|
|
2.58
|
|
|
2.10
|
|
|
0.48
|
|
Total production costs
|
$
|
10.13
|
|
|
$
|
11.67
|
|
|
$
|
(1.54
|
)
|
|
$
|
10.98
|
|
|
$
|
12.27
|
|
|
$
|
(1.29
|
)
|
____________________________
|
|
(1)
|
Below are reconciliations of transportation and processing costs (a 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 with transportation and processing costs reflected on the Condensed Consolidated Statements of Operations 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 and is a more comparable measure to the operating costs of its peers. 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. Refer to
Note 2 – Revenue
in Part 1, Item I of this Quarterly Report on Form 10-Q.
|
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|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
(1)
|
|
Change
|
|
2018
|
|
2017
(1)
|
|
Change
|
|
(in millions)
|
Adjusted transportation and processing costs
|
$
|
43.8
|
|
|
$
|
60.2
|
|
|
$
|
(16.4
|
)
|
|
$
|
134.1
|
|
|
$
|
202.6
|
|
|
$
|
(68.5
|
)
|
Transportation and processing costs deducted from oil and condensate, gas and NGL sales
|
(15.8
|
)
|
|
—
|
|
|
(15.8
|
)
|
|
(40.9
|
)
|
|
—
|
|
|
(40.9
|
)
|
Transportation and processing costs, as presented
|
$
|
28.0
|
|
|
$
|
60.2
|
|
|
$
|
(32.2
|
)
|
|
$
|
93.2
|
|
|
$
|
202.6
|
|
|
$
|
(109.4
|
)
|
|
(per Boe)
|
Adjusted transportation and processing costs
|
$
|
3.04
|
|
|
$
|
4.26
|
|
|
$
|
(1.22
|
)
|
|
$
|
3.34
|
|
|
$
|
4.93
|
|
|
$
|
(1.59
|
)
|
Transportation and processing costs deducted from oil and condensate, gas and NGL sales
|
(1.10
|
)
|
|
—
|
|
|
(1.10
|
)
|
|
(1.02
|
)
|
|
—
|
|
|
(1.02
|
)
|
Transportation and processing costs, as presented
|
$
|
1.94
|
|
|
$
|
4.26
|
|
|
$
|
(2.32
|
)
|
|
$
|
2.32
|
|
|
$
|
4.93
|
|
|
$
|
(2.61
|
)
|
____________________________
|
|
(1)
|
Prior period amounts have not been adjusted under the modified retrospective method for the new revenue recognition rule. Refer to
Note 2 – Revenue
in Part 1, Item 1 of this Quarterly Report on Form 10-Q.
|
Lease operating expense (LOE).
QEP's LOE
decrease
d
$11.6 million
, or
15%
, in the
third quarter
of
2018
compared to the
third quarter
of
2017
primarily due to the Pinedale Divestiture. Excluding Pinedale, LOE
decrease
d
$3.3 million
, primarily driven by decreases in the Williston Basin and Haynesville/Cotton Valley due to lower workover expense and the Uinta Basin Divestiture, partially offset by increases in the Permian Basin due to the 2017 Permian Basin Acquisition, and increased power and fuel, maintenance and repairs and labor expenses.
During the
third quarter
of
2018
, LOE
decrease
d
$0.90
per Boe, or
17%
, compared with the
third quarter
of
2017
and decreased 28% per Boe excluding the Pinedale Divestiture, primarily due to lower cost production from the 2018 horizontal well completions in the Permian Basin, Williston Basin and Haynesville/Cotton Valley, and decreased workover expense in the Williston Basin and Haynesville/Cotton Valley.
QEP's LOE
decrease
d
$11.8 million
in the
first three quarters
of
2018
compared to the
first three quarters
of
2017
, due to the Pinedale Divestiture. Excluding Pinedale, LOE
increase
d
$16.8 million
, primarily driven by increases in the Permian Basin due to the 2017 Permian Basin Acquisition, and increased maintenance and repairs, power and fuel and labor expenses. These increases were partially offset by decreases in workover expense in the Williston and Permian basins.
During the
first three quarters
of
2018
, LOE
decrease
d
$0.18
per Boe, or
3%
, compared with the
first three quarters
of
2017
and decreased 17% excluding the Pinedale Divestiture primarily due to lower cost production from the 2018 horizontal well completions in the Permian Basin and Haynesville/Cotton Valley, partially offset by an increase in our Williston Basin rate due to declining production volumes.
Adjusted transportation and processing costs.
Adjusted transportation and processing costs
decrease
d
$16.4 million
, or
27%
, during the
third quarter
of
2018
compared to the
third quarter
of
2017
. The
decrease
in expense was primarily attributable to the Pinedale Divestiture and the Uinta Basin Divestiture. These decreases were partially offset by the recovery of fees in the third quarter of 2017 for historical unutilized gathering and transportation capacity in Haynesville/Cotton Valley that was charged to QEP by the operator of wells in which QEP had a working interest and increased production in the
third quarter
of
2018
.
During the
third quarter
of
2018
, adjusted transportation and processing costs
decrease
d
$1.22
per Boe, or
29%
, compared to the
third quarter
of
2017
, due to the Pinedale Divestiture, which had higher adjusted transportation and processing costs per Boe. Excluding the Pinedale Divestiture, adjusted transportation and processing costs per Boe were down 17% due to a decrease in the Permian Basin, partially offset by an increase in Haynesville/Cotton Valley during the
third quarter
of
2018
compared to the
third quarter
of
2017
. The cost per Boe decrease in the Permian Basin was driven by increased production and associated throughput under lower cost transportation and processing contracts. The cost per Boe increased in Haynesville/Cotton Valley due to the recovery of fees in the third quarter of 2017 for historical unutilized gathering and transportation capacity that was charged to QEP by the operator of wells in which QEP had a working interest, partially offset by increased production in the
third quarter
of
2018
.
Adjusted transportation and processing costs
decrease
d
$68.5 million
, or
34%
, during the
first three quarters
of
2018
compared to the
first three quarters
of
2017
. The
decrease
in expense was primarily attributable to the Pinedale Divestiture and the Uinta Basin Divestiture. These decreases were partially offset by the recovery of fees in 2017 for historical unutilized gathering and transportation capacity in Haynesville/Cotton Valley that was charged to QEP by the operator of wells in which QEP had a working interest and increased production in the
first three quarters
of
2018
.
During the
first three quarters
of
2018
, adjusted transportation and processing costs
decrease
d
$1.59
per Boe, or
32%
, compared to the
first three quarters
of
2017
, due to the Pinedale Divestiture, which had higher adjusted transportation and processing costs per Boe. Excluding the Pinedale Divestiture, adjusted transportation and processing costs per Boe were down 21% due to a decrease in Haynesville/Cotton Valley and the Permian Basin during the
first three quarters
of
2018
compared to the
first three quarters
of
2017
. The cost per Boe decreased in Haynesville/Cotton Valley due to increased production in 2018, partially offset by the recovery of fees in 2017 for historical unutilized gathering and transportation capacity that was charged to QEP by the operator of wells in which QEP had a working interest in 2017. The cost per Boe decrease in the Permian Basin was driven by increased production and associated throughput under lower cost transportation and processing contracts in 2018.
General and administrative (G&A) expense.
During the
third quarter
of
2018
, G&A expense
increase
d
$4.9 million
, or
11%
, compared to the
third quarter
of
2017
. During the
third quarter
of
2018
, QEP incurred
$12.8 million
in restructuring costs associated with the implementation of our Strategic Initiatives (refer to
Note 8 – Restructuring
, in Item I of Part I of this Quarterly Report on Form 10-Q)
.
In addition to these restructuring related costs, QEP recognized a $4.5 million increase related to reduced overhead recoveries, primarily associated with our Pinedale Divestiture and a $2.0 million increase in outside services expenses. These increases were partially offset by an $8.2 million decrease in legal expenses and loss contingencies and a $2.9 million decrease in share-based compensation and changes in the mark-to-market value of the nonqualified, unfunded deferred compensation plan (the Wrap Plan).
During the
first three quarters
of
2018
, G&A expense
increase
d
$55.9 million
, or
52%
, compared to the
first three quarters
of
2017
. During the
first three quarters
of
2018
, QEP incurred
$30.2 million
in restructuring costs associated with the implementation of our Strategic Initiatives (refer to
Note 8 – Restructuring
, in Item I of Part I of this Quarterly Report on Form 10-Q)
.
In addition to these restructuring related costs, QEP recognized a $17.8 million increase in share-based compensation and changes in the mark-to-market value of the Wrap Plan, a $12.7 million increase related to reduced overhead recoveries, primarily associated with our Pinedale Divestiture, a $4.0 million increase in outside services, a $2.5 million increase in bad debt expense and increases in labor, benefits and employee expenses of $1.3 million. These increases were partially offset by a $5.0 million decrease in legal expenses and loss contingencies.
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
increase
d
$8.9 million
, or
31%
, in the
third quarter
of
2018
compared to the
third quarter
of
2017
, primarily due to increased oil pricing and increased oil and condensate production in the Permian and Williston basins, and increased gas production in Haynesville/Cotton Valley, partially offset by the Pinedale Divestiture.
During the
third quarter
of
2018
, production and property taxes
increase
d
$0.58
per Boe, or
29%
, compared to the
third quarter
of
2017
, but increased 27% excluding the Pinedale Divestiture. The 27% increase was due to an increase in average field-level equivalent prices in the Permian and Williston basins offset by a lower rate per Boe in Haynesville/Cotton Valley due to lower non-operated ad valorem charges and franchise taxes per Boe and severance tax exemptions on production from horizontal well development.
Production and property taxes
increase
d
$17.8 million
, or
21%
, in the
first three quarters
of
2018
compared to the
first three quarters
of
2017
, primarily due to increased oil pricing and increased oil and condensate production in the Permian Basin, and increased gas production in Haynesville/Cotton Valley, partially offset by the Pinedale Divestiture.
During the
first three quarters
of
2018
, production and property taxes
increase
d
$0.48
per Boe, or
23%
, compared to the
first three quarters
of
2017
, but increased 21% excluding the Pinedale Divestiture. The 21% increase was due to an increase in average field-level equivalent prices in the Permian and Williston basins, partially offset by a lower rate per Boe in Haynesville/Cotton Valley due to lower non-operated ad valorem charges and franchise taxes per Boe and severance tax exemptions on production from horizontal well development.
Depreciation, depletion and amortization (DD&A).
DD&A expense
increase
d
$58.0 million
in the
third quarter
of
2018
compared to the
third quarter
of
2017
, primarily due to increased production and a higher DD&A rate in the Permian Basin and Haynesville/Cotton Valley, partially offset by lower DD&A due to the Pinedale Divestiture and the early September 2018 Uinta Basin Divestiture.
DD&A expense
increase
d
$113.4 million
in the
first three quarters
of
2018
compared to the
first three quarters
of
2017
, primarily due to increased production and a higher DD&A rate in the Permian Basin and Haynesville/Cotton Valley, partially offset by lower DD&A due to the Pinedale Divestiture and the early September 2018 Uinta Basin Divestiture.
Exploration expense.
Exploration expense
decrease
d
$21.3 million
during the
third quarter
of
2018
compared to the
third quarter
of
2017
, primarily due to charging $21.2 million of exploratory well costs in 2017 related to the Central Basin Platform exploration project to exploration expense. During the
third quarter
of
2017
, based on well performance and the analysis of the ultimate economic feasibility of this exploration project, QEP determined it would no longer pursue the development of the Central Basin Platform exploration project.
Exploration expense
decrease
d
$21.6 million
during the
first three quarters
of
2018
compared to the
first three quarters
of
2017
, primarily due to charging $21.2 million of exploratory well costs in 2017 related to the Central Basin Platform exploration project to exploration expense. During the
third quarter
of
2017
, based on well performance and the analysis of the ultimate economic feasibility of this exploration project, QEP determined it would no longer pursue the development of the Central Basin Platform exploration project.
Impairment expense.
During the
third quarter
of
2017
, QEP recorded an impairment charge of
$28.3 million
, which were primarily related to the impairment of unproved leasehold acreage in the Central Basin Platform.
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 related to 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.
Net gain (loss) from asset sales, inclusive of restructuring costs.
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 Pinedale Divestiture, partially offset by a pre-tax
loss
on sale 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 8 – Restructuring
, in Item I of Part I of this Quarterly Report on Form 10-Q for more information). During the
third quarter
of
2017
, QEP recognized a
gain
on the sale of assets of
$185.4 million
primarily related to the Pinedale Divestiture, in which we recorded a pre-tax
gain
on sale of
$178.8 million
, and the sale of Other Northern properties.
During the
first three quarters
of
2018
, QEP recognized a
gain
on the sale of assets of
$26.7 million
, primarily related to a net pre-tax
gain
on sale of
$37.9 million
related to the divestiture of properties outside our main operating areas and an additional pre-tax
gain
on sale of
$1.2 million
related to the Pinedale Divestiture, partially offset by a pre-tax
loss
on sale 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 8 – Restructuring
, in Item I of Part I of this Quarterly Report on Form 10-Q for more information). During the
first three quarters
of
2017
, QEP recognized a
gain
on the sale of assets of
$205.2 million
primarily related to the Pinedale Divestiture, in which we recorded a pre-tax
gain
on sale of
$178.8 million
, and the sale of Other Northern properties.
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
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
third quarter
of
2017
,
losses
on commodity derivative contracts were
$104.3 million
, of which
$86.1 million
were unrealized
losses
on derivative contracts related to production and storage contracts,
$29.9 million
were unrealized
losses
related to the Pinedale Divestiture (Refer to
Note 7 – Derivative Contracts
, in Item I of Part I of the Quarterly Report on Form 10-Q for more information) and
$11.7 million
were realized
gains
.
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). During the
first three quarters
of
2017
,
gains
on commodity derivative contracts were
$163.3 million
, of which
$191.5 million
were unrealized
gains
on derivative contracts related to production and storage contracts,
$29.9 million
were unrealized
losses
related to the Pinedale Divestiture (Refer to
Note 7 – Derivative Contracts
, in Item I of Part I of this Quarterly Report on Form 10-Q for more information) and
$1.7 million
were realized
gains
.
Interest expense.
Interest expense
increase
d
$4.3 million
, or
13%
, during the
third quarter
of
2018
compared to the
third quarter
of
2017
. The
increase
during the
third quarter
of
2018
was primarily related to increased interest on the borrowings under the credit facility, partially offset by lower interest rates on senior notes.
Interest expense
increase
d
$8.8 million
, or
9%
, during the
first three quarters
of
2018
compared to the
first three quarters
of
2017
. The
increase
during the
first three quarters
of
2018
was primarily related to increased interest on the borrowings under the credit facility, partially offset by lower interest rates on senior notes.
Income tax (provision) benefit.
Income tax
expense
increase
d
$5.7 million
during the
third quarter
of
2018
compared to the
third quarter
of
2017
. The
increase
in
expense
was the result of net
income
during the
third quarter
of
2018
compared to a net
loss
during the
third quarter
of
2017
. QEP's income tax expense was impacted by a lower combined effective federal and state income tax rate of
25.5%
during the
third quarter
of
2018
compared to a rate of
49.2%
during the
third quarter
of
2017
. The
decrease
in income tax rate was primarily the result of the Tax Cuts and Job Act (H.R. 1) signed into law in December 2017.
Income tax
benefit
increase
d
$187.3 million
during the
first three quarters
of
2018
compared to the
first three quarters
of
2017
. The
increase
in
benefit
was the result of a net
loss
during the
first three quarters
of
2018
compared to net
income
during the
first three quarters
of
2017
. QEP's income tax
benefit
was impacted by a lower combined effective federal and state income tax rate of
23.5%
during the
first three quarters
of
2018
compared to a rate of
36.9%
during the
first three quarters
of
2017
. The
decrease
in income tax rate was primarily the result of the Tax Cuts and Job Act (H.R. 1) signed into law in December 2017.
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 and Strategic Initiatives. 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 and borrowings under its revolving credit facility will be sufficient to fund its operations and capital expenditures during the next 12 months and the foreseeable future.
During the quarter ended
September 30, 2018
, QEP closed on the Uinta Basin Divestiture as well as the divestiture of other assets outside its main operating areas and used the net cash proceeds to pay down long-term debt outstanding under QEP's revolving credit facility. To the extent that the Company sells additional assets, the Company plans to use the proceeds to fund on-going operations, reduce debt, repurchase shares and for general corporate purposes.
The Company estimates, that as of
September 30, 2018
, it could incur additional indebtedness of approximately
$1.4 billion
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 liquidity could be adversely affected.
Credit Facility
QEP's 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 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 4.00 times consolidated EBITDA (as defined in the credit agreement) commencing with the fiscal quarter ending March 31, 2018, through the fiscal quarter ending December 31, 2018, and 3.75 times thereafter, and (iii) during a ratings trigger period (as defined), a present value coverage ratio under which the present value of the Company's proved reserves must exceed net funded debt by 1.25 times at any time prior to January 1, 2019, must exceed net funded debt by 1.40 times commencing on January 1, 2019 through December 31, 2019, and must exceed net funded debt by 1.50 times at any time on or after January 1, 2020. The Company is currently not subject to the present value coverage ratio. As of
September 30, 2018
and
2017
, QEP was in compliance with the covenants under the credit agreement.
During the
nine months ended
September 30, 2018
, QEP's weighted-average interest rate on borrowings from its credit facility was
4.30%
. As of
September 30, 2018
, QEP had
$375.5 million
of borrowings outstanding and
$0.3 million
in letters of credit outstanding under the credit facility. As of
December 31, 2017
, QEP had
$89.0 million
of borrowings outstanding and
$1.0 million
in letters of credit outstanding under the credit facility. As of
October 31, 2018
, QEP had
$370.0 million
of borrowings outstanding, had
$0.3 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, 2018
, totaled
$2,099.3 million
principal amount and are comprised of five issuances as follows:
|
|
•
|
$51.7 million
6.80% Senior Notes due March 2020;
|
|
|
•
|
$397.6 million
6.875% Senior Notes due March 2021;
|
|
|
•
|
$500.0 million
5.375% Senior Notes due October 2022;
|
|
|
•
|
$650.0 million
5.25% Senior Notes due May 2023; and
|
|
|
•
|
$500.0 million
5.625% Senior Notes due March 2026.
|
Cash Flow from Operating Activities
Cash flows from operating activities are primarily affected by oil and condensate, gas and NGL production volumes and commodity prices (including the effects of settlements of the Company's derivative contracts) and by changes in working capital. QEP typically enters into commodity derivative transactions covering a substantial, but varying, portion of its anticipated future oil and gas production for the next 12 to 24 months.
Net cash provided by (used in) operating activities is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
Change
|
|
(in millions)
|
Net income (loss)
|
$
|
(382.3
|
)
|
|
$
|
119.0
|
|
|
$
|
(501.3
|
)
|
Non-cash adjustments to net income (loss)
|
1,076.1
|
|
|
318.7
|
|
|
757.4
|
|
Changes in operating assets and liabilities
|
(18.9
|
)
|
|
45.1
|
|
|
(64.0
|
)
|
Net cash provided by (used in) operating activities
|
$
|
674.9
|
|
|
$
|
482.8
|
|
|
$
|
192.1
|
|
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
,
$1,076.1 million
of non-cash adjustments to the net
loss
and
$18.9 million
in changes in operating assets and liabilities. Non-cash adjustments to the net
loss
of
$1,076.1 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
$28.3 million
of share-based compensation expense, partially offset by
$119.6 million
of deferred income taxes. The
decrease
in changes in operating assets and liabilities of
$18.9 million
primarily resulted from an
increase
in accounts receivable of
$49.8 million
, partially offset by a
decrease
in other assets of
$18.8 million
and an
increase
in accounts payable and accrued expenses of
$11.8 million
.
Net cash
provided by
operating activities was
$482.8 million
during the
first three quarters
of
2017
, which included
$119.0 million
of net
income
,
$318.7 million
of non-cash adjustments to net
income
and a
$45.1 million
increase
in changes in operating assets and liabilities. Non-cash adjustments to net
income
of
$318.7 million
primarily included DD&A expense of
$560.2 million
and
$68.5 million
of deferred income taxes, partially offset by a net
gain
on asset sales of
$205.2 million
and unrealized
gains
on derivative contracts of
$161.6 million
. The
increase
in changes in operating assets and liabilities primarily resulted from a
decrease
in accounts receivable of
$18.5 million
, an
increase
in accounts payable and accrued expenses of
$17.8 million
and an
increase
in production and property taxes of
$7.3 million
, partially offset by a
decrease
in the ARO liability of
$3.0 million
.
Cash Flow from Investing Activities
A comparison of capital expenditures for the
first three quarters
of
2018
and
2017
, are presented in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
Change
|
|
(in millions)
|
Property acquisitions
(1)
|
$
|
48.3
|
|
|
$
|
94.5
|
|
|
$
|
(46.2
|
)
|
Property, plant and equipment capital expenditures
|
988.2
|
|
|
847.6
|
|
|
140.6
|
|
Total accrued capital expenditures
|
1,036.5
|
|
|
942.1
|
|
|
94.4
|
|
Change in accruals and other non-cash adjustments
|
43.9
|
|
|
(68.0
|
)
|
|
111.9
|
|
Total cash capital expenditures
|
$
|
1,080.4
|
|
|
$
|
874.1
|
|
|
$
|
206.3
|
|
____________________________
|
|
(1)
|
Excludes acquisition deposits held in escrow of
$36.6 million
for the
nine months ended
September 30, 2017
.
|
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), an
increase
of
$140.6 million
compared to the
first three quarters
of
2017
. In the
first three quarters
of
2018
, QEP's significant capital expenditures included
$689.7 million
in the Permian Basin (including midstream infrastructure of
$21.0 million
, primarily related to oil and gas gathering),
$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.
In the
first three quarters
of
2017
, on an accrual basis, the Company invested
$847.6 million
on property, plant and equipment capital expenditures (which excludes property acquisitions), including
$489.1 million
in the Permian Basin,
$195.4 million
in the Williston Basin,
$121.2 million
in Haynesville/Cotton Valley and
$24.8 million
in Pinedale. In addition, during the
first three quarters
of
2017
, QEP acquired various oil and gas properties, primarily proved and unproved leaseholds and additional surface acreage primarily in the Permian Basin, for an aggregate purchase price of
$94.5 million
. These cash outflows were partially offset by proceeds from the Pinedale Divestiture, which closed in the third quarter of 2017, and the sale of other assets of approximately
$787.9 million
in the aggregate.
The mid-point of our
2018
forecasted capital expenditures (excluding property acquisitions) is
$1,165.0 million
. QEP intends to fund capital expenditures (excluding property acquisitions) with cash flow from operating activities and borrowings under the credit facility. The aggregate levels of capital expenditures for
2018
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
2018
, net cash
provided by
financing activities was
$191.8 million
compared to net cash
used in
financing activities of
$20.2 million
in the
first three quarters
of
2017
. During the
first three quarters
of
2018
, QEP had borrowings from the 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 had a decrease in checks outstanding in excess of cash balances of
$28.7 million
. During the
first three quarters
of
2017
, QEP had a decrease in checks outstanding in excess of cash balances of
$12.3 million
, had treasury stock repurchases of
$6.8 million
and paid long-term debt issuance costs of
$1.1 million
.
As of
September 30, 2018
, long-term debt consisted of
$2,451.1 million
, of which
$2,099.3 million
is senior notes,
$375.5 million
outstanding on the credit facility and a
$23.7 million
reduction related to the net original issue discount and unamortized debt issuance costs.
Significant Accounting Policies
Refer to
Note 2 – Revenue
in Part 1, Item 1 of this Quarterly Report on Form 10-Q for changes in QEP's revenue recognition policy as a result of the adoption of ASC Topic 606, effective January 1, 2018.