Delaware
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95-2636730
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(State of incorporation)
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(I.R.S. Employer Identification No.)
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Title of each class
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Name of each exchange on which registered
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Common Stock, par value $0.01 per share
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NASDAQ Global Select Market
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Large accelerated filer
x
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Accelerated filer
o
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Non-accelerated filer
£
(Do not check if a smaller reporting company)
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Smaller reporting company
o
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PART I
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Page
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PART II
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PART III
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PART IV
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•
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changes in worldwide production volumes and demand, including economic conditions that might impact demand;
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•
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volatility of commodity prices for crude oil, natural gas, and natural gas liquids ("NGLs") and the risk of an extended period of depressed prices;
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•
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reductions in the borrowing base under our revolving credit facility;
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•
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impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder, and the costs to comply with those laws and regulations;
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•
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declines in the value of our crude oil, natural gas, and NGLs properties resulting in further impairments;
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•
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changes in estimates of proved reserves;
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•
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inaccuracy of estimated reserves and production rates;
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•
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potential for production decline rates from our wells being greater than expected;
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•
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timing and extent of our success in discovering, acquiring, developing, and producing reserves;
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•
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availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production;
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•
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timing and receipt of necessary regulatory permits;
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•
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risks incidental to the drilling and operation of crude oil and natural gas wells;
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•
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losses from our Gas Marketing segment exceeding our expectations;
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•
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difficulties in integrating our operations as a result of any significant acquisitions, including our recent acquisitions in the Delaware Basin;
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•
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increases or changes in operating costs, severance and ad valorem taxes, and increases or changes in drilling, completion and facilities costs;
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•
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increases or adverse changes in construction costs and procurement costs associated with future build out of mid-stream related assets;
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•
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future cash flows, liquidity, and financial condition;
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•
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competition within the oil and gas industry;
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•
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availability and cost of capital;
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•
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our success in marketing crude oil, natural gas, and NGLs;
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•
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effect of crude oil and natural gas derivatives activities;
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•
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impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events;
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•
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cost of pending or future litigation;
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•
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effect that acquisitions we may pursue have on our capital investments;
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•
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our ability to retain or attract senior management and key technical employees; and
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•
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success of strategic plans, expectations and objectives for our future operations.
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•
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Multi-year project inventory in premier crude oil, natural gas, and NGLs plays.
We have a significant operational presence in two premier U.S. onshore basins providing us with approximately 2,600 potential horizontal drilling locations from our total proved and unproved leasehold. The primary focus for development is currently in the Wattenberg Field and the Delaware Basin. We believe that our inventory of drilling locations, the majority of which reflect 4,000 to 10,000 foot horizontal laterals, will allow us to continue to grow our proved reserves and production at attractive rates of return utilizing our current internal long-term commodity price projections and our current expected cost structure. Our 2017 drilling and completion operations are expected to specifically focus on the middle core of the Wattenberg Field and our newly acquired Delaware Basin assets. In the Wattenberg Field, we have identified a substantial inventory consisting of approximately 700 proved undeveloped horizontal drilling locations and an additional approximately 1,100 probable horizontal drilling locations. Through our acquisitions in the Delaware Basin, we added approximately 20 proved undeveloped horizontal drilling locations, which were included in the 785 gross potential drilling locations that were identified on our
62,500
net acres of leasehold. At the time of the initial acquisition, our undeveloped location count was based on wells expected to be drilled with horizontal lateral lengths ranging from 4,000 to 10,000 horizontal feet. We believe that with additional development and exploration activity, together with advances in technology, we may be able to access additional productive zones in the Delaware Basin, which could significantly increase our inventory of undeveloped locations.
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•
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Strong liquidity position.
As of
December 31, 2016
, we had a total liquidity position of
$932.4 million
, comprised of
$244.1 million
of cash and cash equivalents and
$688.3 million
available for borrowing under our revolving credit facility. During 2016, we raised in excess of $1.4 billion of new capital, net of issuance costs.
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•
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In March 2016, we raised
$296.6 million
, net of issuance costs, from the sale of
5.9 million
shares of common stock.
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•
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In September 2016, we issued
9.1 million
shares of common stock for net proceeds of
$558.5 million
,
$400.0 million
of 6.125% senior unsecured notes due in 2024 ("2024 Senior Notes") for net proceeds of
$392.2 million
, and $200.0 million of 1.125% convertible senior notes due in 2021 for net proceeds of
$193.9 million
.
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•
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We also issued
9.4 million
shares of common stock valued at
$690.7 million
in December 2016 as partial consideration to the sellers for the initial Delaware Basin acquisition.
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•
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In December 2016, we increased the aggregate commitment under our revolving credit facility to $700 million.
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•
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Balanced and diversified portfolio across two premier U.S. onshore basins.
We believe we have multiple years of attractive drilling opportunities in both the Wattenberg Field and the Delaware Basin. The completion of the acquisitions of Delaware Basin properties provides us the ability to allocate capital between the two basins to diversify our risk. We expect that this will improve overall economic results and drive our future production and reserve growth. We believe that we will be able to transfer much of our management expertise gained over the years in the Wattenberg Field to the newly acquired Delaware Basin assets. The successful development and exploitation of the acquired leasehold in the Delaware Basin will include execution of our asset integration plan, which consists of transferring our technological expertise to the Delaware Basin, beginning down spacing initiatives, testing various completion designs, successfully developing multiple benches, maintaining an intense focus on cost structure, and utilizing existing personnel and retaining experienced staff. Additionally, we expect the increased geographical diversity of our portfolio to mitigate risks associated with a single dominant producing area, as each basin will have its own operating and competitive dynamic in terms of commodity price markets, service cost areas, takeaway capacity, and regulatory and political considerations.
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•
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Significant operational control in our core areas.
We have, and expect to continue to have, a substantial degree of operational control over our properties. As a result of successfully executing our strategy of acquiring largely concentrated acreage positions with a high working interest, we operate and manage approximately
88
percent of all wells in which we have an interest across all of our operating basins. Our control allows us to manage our drilling, production, operating and administrative costs, and to leverage our technical expertise in our core operating areas. Our leaseholds that are held-by-production further enhance our operational control by providing us flexibility in selecting drilling locations based upon various operational criteria.
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•
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Utilizing technology to focus on efficiency.
In the Wattenberg Field, we have a proven track record of continuing improvement in both costs and productivity of our existing well operations. Our efficiencies are driven by a focus on the use of multi-well pad drilling, extended reach lateral well development, increased fracture stimulation stage density, enhanced fracture stimulation completion design, and improved drilling efficiencies. In 2016, approximately 65 percent of our Wattenberg Field horizontal well spuds were mid- or extended-reach laterals that ranged from approximately 7,000 to 9,500 horizontal feet in length. We have implemented plug-and-perforation completion techniques on all new wells, and increased the number of completion stages to provide a potential uplift to our new well production. We also began using a mono-bore drilling design to reduce drill times and well costs. Through the combination of these techniques, our drilling team has improved our drilling efficiencies with average drill results increasing to approximately 2,200 feet drilled per day in 2016 from approximately 1,800 feet drilled per day in 2015. We believe that we can generate substantial value by leveraging and applying our operating experience in the Wattenberg Field and the Utica Shale to our Delaware Basin properties.
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•
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Commodity derivative program.
Our active use of commodity derivative instruments to protect our investment returns and cash flows was particularly important through the severe commodity price downturn in 2015 and 2016. We have continued this program and have entered into commodity derivative instruments to mitigate a portion of our short-term future exposure to commodity price fluctuations, including crude oil and natural gas collars, fixed-price swaps, and basis swaps. While our commodity derivative program limits the upside benefits we may otherwise receive during periods of higher commodity prices, the program helps protect a portion of our cash flows, borrowing base, and liquidity during periods of depressed commodity prices. We strive to scale our
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•
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Strong environmental, health and safety compliance programs, and community outreach.
We have focused on establishing effective environmental, health and safety programs that are intended to promote safe working practices for our employees and contractors and to help earn the trust and respect of land owners, regulatory agencies, and public officials. We believe this is an important part of our strategy in competing in today’s intensive regulatory and public debate climate. We are also dedicated to being an active and contributing member of the communities in which we operate. We share our success with these communities in various ways, including charitable giving and community event sponsorships.
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•
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Strong management team and operational capabilities.
We have strong and stable management, led by our executive management team. Each member of the team has between 10 and 30 years of experience in the energy and natural resource industry. This experience collectively spans expertise in land, reservoir analysis, operations, accounting, finance, strategy, and general operations, and has helped us continue our growth through periods of commodity price pressure, cost inflation, and challenging operating environments.
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SRL
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MRL
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XRL
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Estimated average lateral length (in feet)
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4,200
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6,900
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9,500
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Expected drilling days (spud-to-spud)
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7
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10
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12
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Estimated percentage of 2017 wells spud
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31%
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33%
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36%
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Estimated percentage of 2017 wells turned-in-line
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35%
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30%
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35%
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Estimated cost per well (in millions)
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$2.5
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$3.5
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$4.5
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•
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The first transaction consisted of the acquisition of certain producing properties and approximately
57,900
acres for approximately
$952.1 million
in cash and the issuance of
9.4 million
shares of our common stock valued at approximately
$690.7 million
at the time the acquisition closed, for total consideration of approximately
$1.64 billion
.
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•
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The second transaction occurred shortly thereafter and included certain developed assets and
4,600
net acres of undeveloped leasehold that is complementary to the initial transaction. This transaction was paid for in cash of
$120.6 million
.
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•
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Crude oil.
In the Wattenberg Field, our crude oil is sold under various purchase contracts with monthly and longer term pricing provisions based on New York Mercantile Exchange ("NYMEX") pricing, adjusted for differentials. Since we do not refine any of our crude oil production, we sell to companies that either transport or resell the commodity, or process the crude oil in their own facilities. Title to the crude oil transfers at the time the crude oil leaves our lease site and is either placed in a truck or enters a pipeline. We have entered into commitments ranging in term from one month to over three years to deliver crude oil to competitive markets, resulting in improved average overall deductions of $4.39 for 2016 compared to $9.95 for 2015. During 2016, there was sufficient take away capacity in the Wattenberg Field for crude oil. This was a function of decreases in drilling activity and corresponding decreases in production from other producers, and the completion of additional crude oil pipelines to the Cushing, Oklahoma market. We believe that there will continue to be adequate take away capacity for crude oil through either pipeline or trucking options in the Wattenberg Field in the near- and mid-term. We continue to pursue various alternatives with respect to crude oil transportation, with a view toward further improving pricing and increasing the amount of crude oil transported by pipeline and limiting our use of trucking. For example, in mid-2015, we began delivering crude oil in accordance with our long term commitment to the White Cliffs Pipeline, LLC ("White Cliffs") pipeline. Our volume of crude oil sales going through the White Cliffs pipeline in 2016 was 16 percent of our Wattenberg Field crude oil production compared to 23 percent during the second half of 2015. By having a variety of off-take arrangements, we seek to optimize our marketing to result in the best possible net realized price per barrel. The White Cliffs agreement is one of several we have entered into to facilitate deliveries of a portion of our crude oil to the Cushing, Oklahoma market. In addition to the White Cliffs agreement, we have signed a long-term agreement with Saddle Butte Rockies Midstream, LLC for gathering of crude oil at the wellhead by pipeline from several of our producing pads in the Wattenberg Field, with a view toward minimizing truck traffic, increasing reliability, reducing the overall physical footprint of our well pads, and reducing emissions. We began delivering crude oil into this pipeline during the fourth quarter of 2015. The system became fully operational in 2016 and we did not experience any subsequent curtailment of operations due to lack of takeaway capacity for crude oil in the basin. We do not expect to experience any curtailments in 2017.
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•
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Natural gas.
We sell substantially all of our natural gas to midstream service providers and marketers. We have entered into firm gathering and processing agreements for all of our natural gas production in the Wattenberg Field to ensure there is infrastructure available to process the gas and deliver our product to market. In the Wattenberg Field, the majority of our leasehold is dedicated to our primary midstream provider, DCP, which gathers and processes natural gas produced in the basin and sells our residue gas to various markets. We also sell natural gas into a system owned and operated by Aka, and have committed production from dedicated acreage and a drilling program with a specific number of wells to be drilled and completed by the end of 2017. Pursuant to the agreement, Aka is required to install and operate, or contract for the use of, facilities necessary to receive and purchase the production volumes committed under the agreement.
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•
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NGLs.
Our NGL sales are priced based upon the components of the product and are correlated to the price of crude oil. In the Wattenberg Field, all of our NGLs are sold by the midstream service provider at the tailgate of the processing plants based on a combination of prices from the Conway hub in Kansas and Mt. Belvieu in Texas where the NGLs are marketed.
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Productive Wells
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As of December 31, 2016
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||||||||||||||||
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Crude Oil
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Natural Gas
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Total
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||||||||||||
Operating Region/Area
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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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||||||
Wattenberg Field
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669
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436.8
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2,193
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1,908.0
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2,862
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2,344.8
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Delaware Basin
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33
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31.5
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—
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—
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33
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31.5
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Utica Shale
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27
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|
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22.2
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3
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3.0
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30
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25.2
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Total productive wells
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729
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490.5
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2,196
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1,911.0
|
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2,925
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2,401.5
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Proved Reserves at December 31, 2016
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||||||||
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Proved Reserves (MMBoe)
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% of Total Proved Reserves
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% Proved Developed
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% Liquids
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Proved Reserves to Production Ratio (in years)(1)
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2016 Production (MBoe)
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||||
Wattenberg Field
|
305.3
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|
89
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%
|
|
29
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%
|
|
58
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%
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|
14.6
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|
20,945
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Delaware Basin
|
32.5
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|
10
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%
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|
22
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%
|
|
68
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%
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|
15.2
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|
178
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Utica Shale
|
3.6
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|
1
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%
|
|
100
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%
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|
56
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%
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3.4
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|
1,053
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Total proved reserves
|
341.4
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|
100
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%
|
|
29
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%
|
|
59
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%
|
|
16.2
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|
22,176
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As of December 31,
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2016
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2015
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2014
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||||||
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Crude oil (SEC NYMEX - $/Bbl)
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$
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42.75
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$
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50.28
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$
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94.99
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Natural gas (SEC NYMEX - $/MMBtu)
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$
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2.48
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$
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2.59
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$
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4.35
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As of December 31,
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2016
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2015
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2014
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||||||
Proved reserves
|
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||||||
Crude oil and condensate
(MMBbls)
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118
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99
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101
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Natural gas
(Bcf)
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834
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661
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537
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NGLs
(MMBbls)
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84
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64
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60
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Total proved reserves
(MMBoe)
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341
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273
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|
250
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Proved developed reserves
(MMBoe)
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98
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70
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75
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Estimated undiscounted future net cash flows
(in millions)
(1)
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$
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2,681
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$
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2,259
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$
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4,938
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Standardized measure
(in millions)
|
$
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1,421
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$
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1,097
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$
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2,306
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||||||
PV-10 (
in millions)
(2)
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$
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1,675
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$
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1,338
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$
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3,450
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(1)
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Amount represents aggregate undiscounted future net cash flows, before income taxes, estimated by Ryder Scott and NSAI of approximately
$3.3 billion
,
$2.8 billion
, and
$7.3 billion
as of December 31,
2016
,
2015
, and
2014
, respectively, less an internally-estimated undiscounted future income tax expense of approximately
$0.6 billion
,
$0.5 billion
, and
$2.3 billion
, respectively.
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(2)
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PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure.
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As of December 31, 2016
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Operating Region/Area
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Crude Oil and Condensate (MMBbls)
|
|
Natural Gas
(Bcf) |
|
NGLs
(MMBbls)
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|
Crude Oil
Equivalent (MMBoe) |
|
Percent
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|||||
Proved developed
|
|
|
|
|
|
|
|
|
|
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|||||
Wattenberg Field
|
|
25.5
|
|
|
240.6
|
|
|
21.7
|
|
|
87.4
|
|
|
26
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%
|
Delaware Basin
|
|
3.4
|
|
|
13.9
|
|
|
1.6
|
|
|
7.2
|
|
|
2
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%
|
Utica Shale
|
|
1.1
|
|
|
9.9
|
|
|
0.9
|
|
|
3.6
|
|
|
1
|
%
|
Total proved developed
|
|
30.0
|
|
|
264.4
|
|
|
24.2
|
|
|
98.2
|
|
|
29
|
%
|
Proved undeveloped
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
76.6
|
|
|
520.6
|
|
|
54.5
|
|
|
217.9
|
|
|
64
|
%
|
Delaware Basin
|
|
11.6
|
|
|
48.7
|
|
|
5.6
|
|
|
25.3
|
|
|
7
|
%
|
Utica Shale
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
%
|
Total proved undeveloped
|
|
88.2
|
|
|
569.3
|
|
|
60.1
|
|
|
243.2
|
|
|
71
|
%
|
Total proved reserves
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
102.1
|
|
|
761.2
|
|
|
76.2
|
|
|
305.3
|
|
|
89
|
%
|
Delaware Basin
|
|
15.0
|
|
|
62.6
|
|
|
7.2
|
|
|
32.5
|
|
|
10
|
%
|
Utica Shale
|
|
1.1
|
|
|
9.9
|
|
|
0.9
|
|
|
3.6
|
|
|
1
|
%
|
Total proved reserves
|
|
118.2
|
|
|
833.7
|
|
|
84.3
|
|
|
341.4
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
Pricing Scenario - NYMEX
|
|
|
|
|
|
|
|||||||||||
|
Crude Oil (per Bbl) (1)
|
|
Natural Gas (per MMBtu) (1)
|
|
Proved Reserves (MMBoe)
|
|
% Change from December 31, 2016 Estimated Reserves
|
PV-10 (in Millions)
|
PV-10 % Change from December 31, 2016 Estimate Reserves
|
|||||||||
2016 SEC Reserve Report
|
$
|
42.75
|
|
|
$
|
2.48
|
|
|
341.4
|
|
|
—
|
|
$
|
1,675.0
|
|
—
|
|
Alternate Price Scenarios:
|
|
|
|
|
|
|
|
|
|
|||||||||
Lower Price Scenario
|
$
|
30.00
|
|
|
$
|
2.48
|
|
|
326.5
|
|
|
(4
|
)%
|
$
|
705.7
|
|
(58
|
)%
|
Higher Price Scenario
|
$
|
50.00
|
|
|
$
|
2.48
|
|
|
345.7
|
|
|
1
|
%
|
$
|
2,247.0
|
|
34
|
%
|
(1)
|
These prices are the SEC NYMEX prices applied to the calculation of the PV-10 value. Such prices have been applied consistently across each pricing scenario to include the impact of adjusting for deductions for any basin differentials, transportation fees, contractual adjustments, and any Btu adjustments we experienced for the respective commodity.
|
|
|
As of December 31, 2016
|
||||||||||||||||
|
|
Developed
|
|
Undeveloped
|
|
Total
|
||||||||||||
Operating Region/Area
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Wattenberg Field
|
|
96,700
|
|
|
89,200
|
|
|
7,700
|
|
|
6,300
|
|
|
104,400
|
|
|
95,500
|
|
Delaware Basin
|
|
19,586
|
|
|
18,664
|
|
|
49,645
|
|
|
43,837
|
|
|
69,231
|
|
|
62,501
|
|
Utica Shale
|
|
5,454
|
|
|
4,291
|
|
|
61,862
|
|
|
58,162
|
|
|
67,316
|
|
|
62,453
|
|
Total acreage
|
|
121,740
|
|
|
112,155
|
|
|
119,207
|
|
|
108,299
|
|
|
240,947
|
|
|
220,454
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Development Well Drilling Activity
|
|||||||||||||||||||||||||
|
|
Year Ended December 31,
|
|||||||||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|||||||||||||||||||||
Operating Region/Area
|
|
Productive
|
|
In-Process
|
|
Non-Productive (1)
|
|
Productive
|
|
In-Process
|
|
Non-Productive (1)
|
|
Productive
|
|
In-Process
|
|
Non-Productive (1)
|
|||||||||
Wattenberg Field, operated wells
|
|
140
|
|
|
64
|
|
|
2
|
|
|
136
|
|
|
78
|
|
|
4
|
|
|
86
|
|
|
44
|
|
|
2
|
|
Wattenberg Field, non-operated wells
|
|
24
|
|
|
12
|
|
|
—
|
|
|
58
|
|
|
19
|
|
|
—
|
|
|
70
|
|
|
25
|
|
|
—
|
|
Delaware Basin
|
|
1
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Utica Shale
|
|
5
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
5
|
|
|
—
|
|
|
8
|
|
|
4
|
|
|
1
|
|
Other (2)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
Total gross development wells
|
|
170
|
|
|
81
|
|
|
2
|
|
|
198
|
|
|
102
|
|
|
4
|
|
|
168
|
|
|
73
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Represents mechanical failures that resulted in the plugging and abandonment of the respective wells.
|
(2)
|
Includes activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014.
|
|
|
Net Development Well Drilling Activity
|
|||||||||||||||||||||||||
|
|
Year Ended December 31,
|
|||||||||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|||||||||||||||||||||
Operating Region/Area
|
|
Productive
|
|
In-Process
|
|
Non-Productive (1)
|
|
Productive
|
|
In-Process
|
|
Non-Productive (1)
|
|
Productive
|
|
In-Process
|
|
Non-Productive (1)
|
|||||||||
Wattenberg Field, operated wells
|
|
109.7
|
|
|
52.7
|
|
|
1.7
|
|
|
110.8
|
|
|
54.6
|
|
|
2.7
|
|
|
75.8
|
|
|
36.5
|
|
|
1.7
|
|
Wattenberg Field, non-operated wells
|
|
5.0
|
|
|
2.8
|
|
|
—
|
|
|
9.3
|
|
|
4.3
|
|
|
—
|
|
|
14.9
|
|
|
6.3
|
|
|
—
|
|
Delaware Basin
|
|
1.0
|
|
|
4.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Utica Shale
|
|
4.5
|
|
|
—
|
|
|
—
|
|
|
3.0
|
|
|
4.5
|
|
|
—
|
|
|
7.0
|
|
|
3.0
|
|
|
1.0
|
|
Other (2)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2.0
|
|
|
—
|
|
|
—
|
|
Total net development wells
|
|
120.2
|
|
|
60.3
|
|
|
1.7
|
|
|
123.1
|
|
|
63.4
|
|
|
2.7
|
|
|
99.7
|
|
|
45.8
|
|
|
2.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Represents mechanical failures that resulted in the plugging and abandonment of the respective wells.
|
(2)
|
Includes activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014.
|
•
|
bond requirements in order to drill or operate wells;
|
•
|
well locations;
|
•
|
drilling and casing methods;
|
•
|
surface use and restoration of well properties;
|
•
|
well plugging and abandoning;
|
•
|
fluid disposal; and
|
•
|
air emissions.
|
•
|
costs of providing service, including depreciation expense;
|
•
|
allowed rate of return, including the equity component of the capital structure, and related income taxes; and
|
•
|
volume throughput assumptions.
|
•
|
our revenue, profitability and cash flows;
|
•
|
our liquidity;
|
•
|
the quantity and present value of our reserves;
|
•
|
the borrowing base under our revolving credit facility and access to other sources of capital; and
|
•
|
the nature and scale of our operations.
|
•
|
relatively minor changes in regional, national, or global supply and demand;
|
•
|
regional, national, or global economic conditions, and perceived trends in those conditions;
|
•
|
geopolitical factors, such as events that may reduce or increase production from particular oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries, or OPEC; and
|
•
|
regulatory changes.
|
•
|
fluctuations in prices of crude oil, natural gas, and NGLs produced from the wells in the area;
|
•
|
natural disasters such as the flooding that occurred in Northern Colorado in September 2013;
|
•
|
restrictive governmental regulations; and
|
•
|
curtailment of production or interruption in the availability of gathering, processing, or transportation infrastructure and services, and any resulting delays or interruptions of production from existing or planned new wells.
|
•
|
our proved reserves;
|
•
|
the amount of crude oil, natural gas, and NGLs we are able to produce from existing wells;
|
•
|
the prices at which crude oil, natural gas, and NGLs are sold;
|
•
|
the costs to produce crude oil, natural gas, and NGLs; and
|
•
|
our ability to acquire, locate and produce new reserves.
|
•
|
Decreases in commodity prices in recent years have resulted in reduced investment in midstream facilities by some third parties;
|
•
|
Various interest groups have protested the construction of new pipelines, and particularly pipelines near water bodies, in various places throughout the country, and protests have at times physically interrupted pipeline construction activities; and
|
•
|
Some upstream energy companies have in the recent past sought to reject volume commitment agreements with midstream providers in bankruptcy proceedings, and the risk that such efforts will succeed, or that upstream energy company counterparties will otherwise be unable or unwilling to satisfy their volume commitments, may have the effect of reducing investment in midstream infrastructure.
|
•
|
the economically recoverable quantities of crude oil, natural gas, and NGLs attributable to any particular group of properties;
|
•
|
future depreciation, depletion, and amortization (“DD&A”) rates and amounts;
|
•
|
impairments in the value of our assets;
|
•
|
the classifications of reserves based on risk of recovery;
|
•
|
estimates of future net cash flows;
|
•
|
timing of our capital expenditures; and
|
•
|
the amount of funds available for us to borrow under our revolving credit facility.
|
•
|
crude oil, natural gas, and NGL prices;
|
•
|
the availability and cost of capital;
|
•
|
drilling and production costs;
|
•
|
availability of drilling services and equipment;
|
•
|
drilling results;
|
•
|
lease expirations;
|
•
|
midstream constraints;
|
•
|
access to and availability of water sourcing and distribution systems;
|
•
|
regulatory approvals; and
|
•
|
other factors.
|
•
|
unusual or unexpected geological formations;
|
•
|
pressures;
|
•
|
fires;
|
•
|
floods;
|
•
|
loss of well control;
|
•
|
loss of drilling fluid circulation;
|
•
|
title problems;
|
•
|
facility or equipment malfunctions;
|
•
|
unexpected operational events;
|
•
|
shortages or delays in the delivery of equipment and services;
|
•
|
unanticipated environmental liabilities;
|
•
|
compliance with environmental and other governmental requirements; and
|
•
|
adverse weather conditions.
|
•
|
incur additional debt;
|
•
|
pay dividends on, redeem, or repurchase stock;
|
•
|
create liens;
|
•
|
make specified types of investments;
|
•
|
apply net proceeds from certain asset sales;
|
•
|
engage in transactions with our affiliates;
|
•
|
engage in sale and leaseback transactions;
|
•
|
merge or consolidate;
|
•
|
restrict dividends or other payments from restricted subsidiaries;
|
•
|
sell equity interests of restricted subsidiaries; and
|
•
|
sell, assign, transfer, lease, convey or dispose of assets.
|
•
|
changes in production volumes, worldwide demand and prices for crude oil and natural gas;
|
•
|
changes in market prices of crude oil and natural gas;
|
•
|
inability to hedge future production at the same pricing level as our current hedges;
|
•
|
changes in securities analysts’ estimates of our financial performance;
|
•
|
fluctuations in stock market prices and volumes, particularly among securities of energy companies;
|
•
|
changes in market valuations and valuation multiples of similar companies;
|
•
|
changes in interest rates;
|
•
|
announcements regarding adverse timing or lack of success in discovering, acquiring, developing, and producing crude oil and natural gas resources;
|
•
|
announcements by us or our competitors of significant contracts, new acquisitions, discoveries, commercial relationships, joint ventures, or capital commitments;
|
•
|
decreases in the amount of capital available to us, including as a result of borrowing base reductions and/or lenders ceasing to participate in our revolving credit facility syndicate;
|
•
|
operating results that fall below market expectations or variations in our quarterly operating results;
|
•
|
loss of a major customer;
|
•
|
loss of a relationship with a partner;
|
•
|
the identification of and severity of environmental events and governmental and other third-party responses to the events; or
|
•
|
additions or departures of key personnel.
|
•
|
The Dodd-Frank Act may limit our ability to enter into hedging transactions, thus exposing us to additional risks related to commodity price volatility; commodity price decreases would then have an increased adverse effect on our profitability and revenues. Reduced hedging may also impair our ability to have certainty with respect to a portion of our cash flows, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves.
|
•
|
If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in connection with our derivative positions, this would likely make it impracticable to implement our current hedging strategy.
|
•
|
Our derivatives counterparties are subject to significant requirements imposed as a result of the Dodd-Frank Act. We expect that these requirements will increase the cost to hedge because there will be fewer counterparties in the market and increased counterparty costs will be passed on to us.
|
|
|
||||||
|
High
|
|
Low
|
||||
|
|
|
|
||||
January 1 - March 31, 2015
|
$
|
55.47
|
|
|
$
|
37.62
|
|
April 1 - June 30, 2015
|
61.41
|
|
|
51.01
|
|
||
July 1 - September 30, 2015
|
61.55
|
|
|
41.17
|
|
||
October 1 - December 31, 2015
|
64.99
|
|
|
52.46
|
|
||
January 1 - March 31, 2016
|
60.56
|
|
|
42.68
|
|
||
April 1 - June 30, 2016
|
65.86
|
|
|
51.92
|
|
||
July 1 - September 30, 2016
|
71.00
|
|
|
50.12
|
|
||
October 1 - December 31, 2016
|
84.88
|
|
|
59.82
|
|
Period
|
|
Total Number of Shares Purchased (1)
|
|
Average Price Paid per Share
|
|||
|
|
|
|
|
|||
October 1 - 31, 2016
|
|
5,742
|
|
|
$
|
66.98
|
|
November 1 - 30, 2016
|
|
—
|
|
|
$
|
—
|
|
December 1 - 31, 2016
|
|
19,969
|
|
|
$
|
73.37
|
|
Total fourth quarter 2016 purchases
|
|
25,711
|
|
|
$
|
71.94
|
|
(1)
|
Purchases primarily represent shares purchased from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans.
|
|
|
Year Ended/As of December 31,
|
||||||||||||||||||
|
|
2016 (1)
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
|
(in millions, except per share data and as noted)
|
||||||||||||||||||
Statement of Operations (From Continuing Operations) (2):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Crude oil, natural gas and NGLs sales
|
|
$
|
497.4
|
|
|
$
|
378.7
|
|
|
$
|
471.4
|
|
|
$
|
340.8
|
|
|
$
|
228.0
|
|
Commodity price risk management gain (loss), net of actual settlements and changes in mark-to-market valuation adjustments
|
|
(125.7
|
)
|
|
$
|
203.2
|
|
|
310.3
|
|
|
(23.9
|
)
|
|
29.3
|
|
||||
Total revenues
|
|
382.9
|
|
|
595.3
|
|
|
856.2
|
|
|
392.7
|
|
|
307.1
|
|
|||||
Income (loss) from continuing operations
|
|
(245.9
|
)
|
|
(68.3
|
)
|
|
107.3
|
|
|
(21.1
|
)
|
|
(19.4
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Earnings (loss) per share from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
$
|
(5.01
|
)
|
|
$
|
(1.74
|
)
|
|
$
|
3.00
|
|
|
$
|
(0.65
|
)
|
|
$
|
(0.70
|
)
|
Diluted
|
|
(5.01
|
)
|
|
(1.74
|
)
|
|
2.93
|
|
|
(0.65
|
)
|
|
(0.70
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Statement of Cash Flows:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash flows from:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating activities
|
|
$
|
486.3
|
|
|
$
|
411.1
|
|
|
$
|
236.7
|
|
|
$
|
159.2
|
|
|
$
|
174.7
|
|
Investing activities
|
|
(1,509.1
|
)
|
|
(604.3
|
)
|
|
(474.1
|
)
|
|
(217.1
|
)
|
|
(451.9
|
)
|
|||||
Financing activities
|
|
1,266.1
|
|
|
178.0
|
|
|
60.3
|
|
|
248.7
|
|
|
271.4
|
|
|||||
Capital expenditures from development and exploration activities (3)
|
|
436.9
|
|
|
599.5
|
|
|
623.8
|
|
|
384.7
|
|
|
344.2
|
|
|||||
Acquisitions of crude oil and natural gas properties
|
|
1,073.7
|
|
|
—
|
|
|
—
|
|
|
9.7
|
|
|
312.2
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Balance Sheet:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
|
$
|
4,485.8
|
|
|
$
|
2,370.5
|
|
|
$
|
2,331.1
|
|
|
$
|
1,991.7
|
|
|
$
|
1,777.9
|
|
Working capital
|
|
129.2
|
|
|
30.7
|
|
|
89.5
|
|
|
90.0
|
|
|
(67.6
|
)
|
|||||
Total debt,
net of unamortized discount and debt issuance costs
|
|
1,044.0
|
|
|
642.4
|
|
|
655.5
|
|
|
593.9
|
|
|
637.5
|
|
|||||
Total equity
|
|
2,622.8
|
|
|
1,287.2
|
|
|
1,137.4
|
|
|
967.6
|
|
|
703.2
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Pricing and Production Expenses From Continuing Operations (per Boe and as a percent of sales for Production Taxes):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Average sales price (excluding net settlements on derivatives)
|
|
$
|
22.43
|
|
|
$
|
24.64
|
|
|
$
|
50.72
|
|
|
$
|
52.23
|
|
|
$
|
46.85
|
|
Lease operating expenses
|
|
$
|
2.70
|
|
|
$
|
3.71
|
|
|
$
|
4.56
|
|
|
$
|
5.18
|
|
|
$
|
5.54
|
|
Transportation, gathering, and processing
|
|
$
|
0.83
|
|
|
$
|
0.66
|
|
|
$
|
0.49
|
|
|
$
|
0.79
|
|
|
$
|
0.56
|
|
Production taxes
|
|
$
|
1.42
|
|
|
$
|
1.20
|
|
|
$
|
2.76
|
|
|
$
|
3.33
|
|
|
$
|
2.86
|
|
Production taxes as a percent of sales
|
|
6.3
|
%
|
|
4.9
|
%
|
|
5.4
|
%
|
|
6.4
|
%
|
|
6.1
|
%
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Production (MBoe):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Production from continuing operations
|
|
22,175.9
|
|
|
15,369.4
|
|
|
9,294.4
|
|
|
6,524.7
|
|
|
4,866.5
|
|
|||||
Production from discontinued operations
|
|
—
|
|
|
—
|
|
|
1,093.0
|
|
|
2,032.6
|
|
|
3,458.7
|
|
|||||
Total production
|
|
22,175.9
|
|
|
15,369.4
|
|
|
10,387.4
|
|
|
8,557.3
|
|
|
8,325.2
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total proved reserves (MMBoe) (4)(5)
|
|
341.4
|
|
|
272.8
|
|
|
250.1
|
|
|
265.8
|
|
|
192.8
|
|
(1)
|
In 2016, we closed acquisitions in the Delaware Basin for aggregate consideration of approximately
$1.76 billion
. See footnotes titled Properties and Equipment - Delaware Basin Acreage Acquisition and Business Combination to our consolidated financial statements included elsewhere in this report for further information regarding these acquisitions.
|
(2)
|
In 2014, we completed the sale of our ownership interest in PDCM. Our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations. See footnote titled Divestiture and Discontinued Operations to our consolidated financial statements included elsewhere in this report for further information regarding this divestiture.
|
(3)
|
Includes impact of change in accounts payable related to capital expenditures.
|
(4)
|
Includes total proved reserves related to our Marcellus Shale and shallow Upper Devonian Appalachian Basin assets of 40 MMBoe and 30 MMBoe as of December 31, 2013 and 2012, respectively. The joint venture that owned these reserves was sold in late 2014.
|
(5)
|
Includes total proved reserves related to our Piceance Basin and North Eastern Colorado ("NECO") assets of
14
MMBoe as of December 31, 2012. These assets were sold in 2013.
|
•
|
The net change in the fair value of unsettled derivative positions in
2016
was a loss of
$333.8 million
compared to a loss of
$35.8 million
in
2015
. The decrease in the fair value of unsettled derivative positions is largely driven by the normal monthly settlements of the commodity derivative instruments in 2016. Additionally, the change in fair value was attributable to hedging positions entered into in 2016 at lower strike prices and the upward shift in the crude oil and natural gas forward curves that occurred during 2016 versus a downward shift in 2015.
|
•
|
Production tax expense increased to
$31.4 million
in 2016 from
$18.4 million
in 2015 due to increased production of
44 percent
and higher overall sales proceeds. Additionally, we had a higher effective production tax rate in 2016 primarily from a reduction in ad valorem credits from the prior year to offset current year severance taxes due.
|
•
|
Impairment of crude oil and natural gas properties was
$10.0 million
in
2016
compared to
$161.6 million
in
2015
. The 2016 impairments are a result of the write-off of certain leases that were no longer part of our development plan and to reflect the fair value of other land and buildings that are held for sale. The Utica Shale was the largest component of the 2015 write-down which included both producing and non-producing crude oil and natural gas properties.
|
•
|
General and administrative expense increased to
$112.5 million
in
2016
compared to
$90.0 million
in
2015
. The increase was attributable to professional and transaction fees related to the Delaware Basin acquisitions and increases in payroll and employee benefits, as we increased our staff by
nine percent
over the course of 2016.
|
•
|
Depreciation, depletion, and amortization expense increased to
$416.9 million
in
2016
compared to
$303.3 million
in
2015
, due to the increase in production volumes from year to year.
|
•
|
We recorded a provision for uncollectible notes receivable of
$44.0 million
in the first quarter of 2016 to impair a note receivable.
|
•
|
Interest expense increased to
$62.0
million in 2016 from
$47.6
million in 2015. The increase was primarily attributable to a $9.3 million charge for the bridge loan commitment related to our initial Delaware Basin acquisition, a $7.4 million increase in interest expense resulting from the issuance of our 2024 Senior Notes, and a $2.9 million increase in interest expense for the issuance of our 2021 Convertible Notes in September 2016. The increases were partially offset by a $5.1 million decrease in interest expense resulting from the net settlement of our 2016 Convertible Notes in May 2016.
|
•
|
top-tier acreage in core geologic positions;
|
•
|
significant drilling inventory with additional expansion through down spacing;
|
•
|
portfolio optionality for capital allocation and diversification; and
|
•
|
the ability to deliver long-term corporate accretion.
|
Acquisition costs:
|
|
||
Cash, net of cash acquired
|
$
|
912,142
|
|
Retirement of seller's debt
|
40,000
|
|
|
Total cash consideration
|
952,142
|
|
|
Common stock, 9.4 million shares
|
690,702
|
|
|
Other purchase price adjustments
|
1,026
|
|
|
Total acquisition costs
|
$
|
1,643,870
|
|
|
|
||
Recognized amounts of identifiable assets acquired and liabilities assumed:
|
|
||
Assets acquired:
|
|
||
Current assets
|
$
|
8,201
|
|
Crude oil and natural gas properties - proved
|
216,000
|
|
|
Crude oil and natural gas properties - unproved
|
1,721,334
|
|
|
Infrastructure, pipeline, and other
|
32,590
|
|
|
Construction in progress
|
12,148
|
|
|
Goodwill
|
62,041
|
|
|
Total assets acquired
|
2,052,314
|
|
|
Liabilities assumed:
|
|
||
Current liabilities
|
(24,844
|
)
|
|
Asset retirement obligations
|
(3,705
|
)
|
|
Deferred tax liabilities, net
|
(379,895
|
)
|
|
Total liabilities assumed
|
(408,444
|
)
|
|
Total identifiable net assets acquired
|
$
|
1,643,870
|
|
|
|
Gross
|
|
Net
|
||
In-process as of December 31, 2015
|
|
102
|
|
|
63.4
|
|
Wells spud during the period
|
|
144
|
|
|
112.2
|
|
Wells turned-in-line to sales
|
|
(170
|
)
|
|
(120.2
|
)
|
Acquired in-process
|
|
5
|
|
|
4.9
|
|
In-process as of December 31, 2016
|
|
81
|
|
|
60.3
|
|
|
Year Ended December 31,
|
||||||||||||||||
|
|
|
|
|
|
|
Percent Change
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2016-2015
|
|
2015-2014
|
||||||||
|
(dollars in millions, except per unit data)
|
|
|
|
|
||||||||||||
Production
|
|
|
|
|
|
|
|
|
|
||||||||
Crude oil (MBbls)
|
8,728
|
|
|
6,984
|
|
|
4,322
|
|
|
25.0
|
%
|
|
61.6
|
%
|
|||
Natural gas (MMcf)
|
51,730
|
|
|
33,302
|
|
|
19,298
|
|
|
55.3
|
%
|
|
72.6
|
%
|
|||
NGLs (MBbls)
|
4,826
|
|
|
2,835
|
|
|
1,756
|
|
|
70.2
|
%
|
|
61.4
|
%
|
|||
Crude oil equivalent (MBoe)
|
22,176
|
|
|
15,369
|
|
|
9,294
|
|
|
44.3
|
%
|
|
65.4
|
%
|
|||
Average Boe per day
|
60,590
|
|
|
42,108
|
|
|
25,464
|
|
|
43.9
|
%
|
|
65.4
|
%
|
|||
Crude Oil, Natural Gas and NGLs Sales
|
|
|
|
|
|
|
|
|
|
||||||||
Crude oil
|
$
|
348.9
|
|
|
$
|
280.3
|
|
|
$
|
348.6
|
|
|
24.5
|
%
|
|
(19.6
|
)%
|
Natural gas
|
91.6
|
|
|
68.0
|
|
|
74.7
|
|
|
34.7
|
%
|
|
(9.0
|
)%
|
|||
NGLs
|
56.9
|
|
|
30.4
|
|
|
48.1
|
|
|
87.2
|
%
|
|
(36.8
|
)%
|
|||
Total crude oil, natural gas, and NGLs sales
|
$
|
497.4
|
|
|
$
|
378.7
|
|
|
$
|
471.4
|
|
|
31.3
|
%
|
|
(19.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
||||||||
Net Settlements on Commodity Derivatives (1)
|
|
|
|
|
|
|
|
|
|
||||||||
Crude oil
|
$
|
165.2
|
|
|
$
|
208.9
|
|
|
$
|
2.3
|
|
|
(20.9
|
)%
|
|
*
|
|
Natural gas
|
42.9
|
|
|
30.0
|
|
|
(3.1
|
)
|
|
43.0
|
%
|
|
*
|
|
|||
Total net settlements on derivatives
|
$
|
208.1
|
|
|
$
|
238.9
|
|
|
$
|
(0.8
|
)
|
|
(12.9
|
)%
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Average Sales Price (excluding net settlements on derivatives)
|
|
|
|
|
|
|
|
|
|
||||||||
Crude oil (per Bbl)
|
$
|
39.96
|
|
|
$
|
40.14
|
|
|
$
|
80.67
|
|
|
(0.4
|
)%
|
|
(50.2
|
)%
|
Natural gas (per Mcf)
|
1.77
|
|
|
2.04
|
|
|
3.87
|
|
|
(13.2
|
)%
|
|
(47.3
|
)%
|
|||
NGLs (per Bbl)
|
11.80
|
|
|
10.72
|
|
|
27.39
|
|
|
10.1
|
%
|
|
(60.9
|
)%
|
|||
Crude oil equivalent (per Boe)
|
22.43
|
|
|
24.64
|
|
|
50.72
|
|
|
(9.0
|
)%
|
|
(51.4
|
)%
|
|||
|
|
|
|
|
|
|
|
|
|
||||||||
Average Costs and Expenses (per Boe)
|
|
|
|
|
|
|
|
|
|
||||||||
Lease operating expenses
|
$
|
2.70
|
|
|
$
|
3.71
|
|
|
$
|
4.56
|
|
|
(27.2
|
)%
|
|
(18.6
|
)%
|
Production taxes
|
1.42
|
|
|
1.20
|
|
|
2.76
|
|
|
18.3
|
%
|
|
(56.5
|
)%
|
|||
Transportation, gathering, and processing expenses
|
0.83
|
|
|
0.66
|
|
|
0.49
|
|
|
25.8
|
%
|
|
34.7
|
%
|
|||
General and administrative expense
|
5.07
|
|
|
5.85
|
|
|
13.29
|
|
|
(13.3
|
)%
|
|
(56.0
|
)%
|
|||
Depreciation, depletion, and amortization
|
18.80
|
|
|
19.73
|
|
|
20.71
|
|
|
(4.7
|
)%
|
|
(4.7
|
)%
|
|||
|
|
|
|
|
|
|
|
|
|
||||||||
Other Costs and Expenses
|
|
|
|
|
|
|
|
|
|
||||||||
Exploration expense
|
$
|
4.7
|
|
|
$
|
1.1
|
|
|
$
|
0.9
|
|
|
*
|
|
|
16.4
|
%
|
Impairment of properties and equipment
|
10.0
|
|
|
161.6
|
|
|
166.8
|
|
|
(93.8
|
)%
|
|
(3.1
|
)%
|
|||
Interest expense
|
62.0
|
|
|
47.6
|
|
|
47.8
|
|
|
30.3
|
%
|
|
(0.6
|
)%
|
|||
|
|
|
|
|
|
|
|
|
|
||||||||
Gas Marketing Contribution Margin (2)
|
$
|
(1.5
|
)
|
|
$
|
(0.8
|
)
|
|
$
|
(0.4
|
)
|
|
(87.5
|
)%
|
|
(100.0
|
)%
|
*
|
Percentage change is not meaningful or equal to or greater than 300% or not applicable.
|
(1)
|
Represents net settlements on derivatives related to crude oil and natural gas sales, which do not include net settlements on derivatives related to gas marketing.
|
(2)
|
Represents sales from gas marketing, net of costs of gas marketing, including net settlements and net change in fair value of unsettled derivatives related to gas marketing activities.
|
|
|
Year Ended December 31,
|
|||||||||||||
|
|
|
|
|
|
|
|
Change
|
|||||||
Production by Operating Region
|
|
2016
|
|
2015
|
|
2014
|
|
2016-2015
|
|
2015-2014
|
|||||
Crude oil (MBbls)
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
8,229.7
|
|
|
6,490.4
|
|
|
4,026.7
|
|
|
26.8
|
%
|
|
61.2
|
%
|
Delaware Basin (1)
|
|
79.5
|
|
|
—
|
|
|
—
|
|
|
*
|
|
|
*
|
|
Utica Shale
|
|
419.1
|
|
|
493.4
|
|
|
295.2
|
|
|
(15.1
|
)%
|
|
67.1
|
%
|
Total
|
|
8,728.3
|
|
|
6,983.8
|
|
|
4,321.9
|
|
|
25.0
|
%
|
|
61.6
|
%
|
Natural gas (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
48,889.1
|
|
|
30,752.8
|
|
|
17,108.9
|
|
|
59.0
|
%
|
|
79.7
|
%
|
Delaware Basin (1)
|
|
373.3
|
|
|
—
|
|
|
—
|
|
|
*
|
|
|
*
|
|
Utica Shale
|
|
2,467.8
|
|
|
2,548.9
|
|
|
2,189.1
|
|
|
(3.2
|
)%
|
|
16.4
|
%
|
Total
|
|
51,730.2
|
|
|
33,301.7
|
|
|
19,298.0
|
|
|
55.3
|
%
|
|
72.6
|
%
|
NGLs (MBbls)
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
4,567.5
|
|
|
2,615.9
|
|
|
1,605.7
|
|
|
74.6
|
%
|
|
62.9
|
%
|
Delaware Basin (1)
|
|
36.1
|
|
|
—
|
|
|
—
|
|
|
*
|
|
|
*
|
|
Utica Shale
|
|
222.2
|
|
|
219.4
|
|
|
150.5
|
|
|
1.3
|
%
|
|
45.8
|
%
|
Total
|
|
4,825.8
|
|
|
2,835.3
|
|
|
1,756.2
|
|
|
70.2
|
%
|
|
61.4
|
%
|
Crude oil equivalent (MBoe)
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
20,945.4
|
|
|
14,231.7
|
|
|
8,483.8
|
|
|
47.2
|
%
|
|
67.8
|
%
|
Delaware Basin (1)
|
|
177.8
|
|
|
—
|
|
|
—
|
|
|
*
|
|
|
*
|
|
Utica Shale
|
|
1,052.7
|
|
|
1,137.7
|
|
|
810.6
|
|
|
(7.5
|
)%
|
|
40.4
|
%
|
Total
|
|
22,175.9
|
|
|
15,369.4
|
|
|
9,294.4
|
|
|
44.3
|
%
|
|
65.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
*
|
Percentage change is not meaningful or equal to or greater than 300%.
|
|
|
Year Ended December 31,
|
||||||||||||||||
Weighted-Average Sales Price by Operating Region
|
|
|
|
|
|
|
|
Change
|
||||||||||
(excluding net settlements on derivatives)
|
|
2016
|
|
2015
|
|
2014
|
|
2016-2015
|
|
2015-2014
|
||||||||
Crude oil (per Bbl)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
$
|
39.99
|
|
|
$
|
40.03
|
|
|
$
|
80.61
|
|
|
(0.1
|
)%
|
|
(50.3
|
)%
|
Delaware Basin (1)
|
|
49.28
|
|
|
—
|
|
|
—
|
|
|
*
|
|
|
*
|
|
|||
Utica Shale
|
|
37.62
|
|
|
41.59
|
|
|
81.52
|
|
|
(9.5
|
)%
|
|
(49.0
|
)%
|
|||
Weighted-average price
|
|
39.96
|
|
|
40.14
|
|
|
80.67
|
|
|
(0.4
|
)%
|
|
(50.2
|
)%
|
|||
Natural gas (per Mcf)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
1.77
|
|
|
2.06
|
|
|
3.94
|
|
|
(14.1
|
)%
|
|
(47.7
|
)%
|
|||
Delaware Basin (1)
|
|
2.78
|
|
|
—
|
|
|
—
|
|
|
*
|
|
|
*
|
|
|||
Utica Shale
|
|
1.58
|
|
|
1.85
|
|
|
3.35
|
|
|
(14.6
|
)%
|
|
(44.8
|
)%
|
|||
Weighted-average price
|
|
1.77
|
|
|
2.04
|
|
|
3.87
|
|
|
(13.2
|
)%
|
|
(47.3
|
)%
|
|||
NGLs (per Bbl)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
11.59
|
|
|
10.58
|
|
|
25.95
|
|
|
9.5
|
%
|
|
(59.2
|
)%
|
|||
Delaware Basin (1)
|
|
17.87
|
|
|
—
|
|
|
—
|
|
|
*
|
|
|
*
|
|
|||
Utica Shale
|
|
15.11
|
|
|
12.43
|
|
|
42.76
|
|
|
21.6
|
%
|
|
(70.9
|
)%
|
|||
Weighted-average price
|
|
11.80
|
|
|
10.72
|
|
|
27.39
|
|
|
10.1
|
%
|
|
(60.9
|
)%
|
|||
Crude oil equivalent (per Boe)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
22.38
|
|
|
24.64
|
|
|
51.10
|
|
|
(9.2
|
)%
|
|
(51.8
|
)%
|
|||
Delaware Basin (1)
|
|
31.50
|
|
|
—
|
|
|
—
|
|
|
*
|
|
|
*
|
|
|||
Utica Shale
|
|
21.88
|
|
|
24.59
|
|
|
46.87
|
|
|
(11.0
|
)%
|
|
(47.5
|
)%
|
|||
Weighted-average price
|
|
22.43
|
|
|
24.64
|
|
|
50.72
|
|
|
(9.0
|
)%
|
|
(51.4
|
)%
|
*
|
Percentage change is not meaningful or equal to or greater than 300%.
|
|
Year Ended December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in millions)
|
||||||
Increase in production from development of existing properties
|
$
|
128.8
|
|
|
$
|
298.5
|
|
Increase in production from acquisitions
|
0.2
|
|
|
—
|
|
||
Decrease in average crude oil price
|
(1.6
|
)
|
|
(283.1
|
)
|
||
Decrease in average natural gas price
|
(14.0
|
)
|
|
(60.9
|
)
|
||
Increase (decrease) in average NGLs price
|
5.2
|
|
|
(47.2
|
)
|
||
Total increase (decrease) in crude oil, natural gas and NGLs sales revenue
|
$
|
118.6
|
|
|
$
|
(92.7
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Commodity price risk management gain (loss), net:
|
|
|
|
|
|
||||||
Net settlements of commodity derivative instruments:
|
|
|
|
|
|
||||||
Crude oil fixed price swaps and collars
|
$
|
165.2
|
|
|
$
|
208.9
|
|
|
$
|
2.3
|
|
Natural gas fixed price swaps and collars
|
41.9
|
|
|
31.0
|
|
|
(3.7
|
)
|
|||
Natural gas basis protection swaps
|
1.0
|
|
|
(1.0
|
)
|
|
0.6
|
|
|||
Total net settlements of commodity derivative instruments
|
208.1
|
|
|
238.9
|
|
|
(0.8
|
)
|
|||
Change in fair value of unsettled commodity derivative instruments:
|
|
|
|
|
|
||||||
Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments
|
(220.0
|
)
|
|
(186.9
|
)
|
|
13.3
|
|
|||
Crude oil fixed price swaps and collars
|
(78.6
|
)
|
|
99.3
|
|
|
256.1
|
|
|||
Natural gas fixed price swaps and collars
|
(37.1
|
)
|
|
53.3
|
|
|
41.7
|
|
|||
Natural gas basis swaps
|
1.9
|
|
|
(1.4
|
)
|
|
—
|
|
|||
Net change in fair value of unsettled commodity derivative instruments
|
(333.8
|
)
|
|
(35.7
|
)
|
|
311.1
|
|
|||
Total commodity price risk management gain (loss), net
|
$
|
(125.7
|
)
|
|
$
|
203.2
|
|
|
$
|
310.3
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(in millions)
|
||||||||||
|
|
|
|
|
|
|
||||||
Geological and geophysical costs, including seismic purchases
|
|
$
|
3.5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Operating, personnel and other
|
|
1.2
|
|
|
1.1
|
|
|
0.9
|
|
|||
Total exploration expense
|
|
$
|
4.7
|
|
|
$
|
1.1
|
|
|
$
|
0.9
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
|
|
|
|
|
|
||||||
Impairment of proved and unproved properties
|
$
|
5.6
|
|
|
$
|
154.6
|
|
|
$
|
161.6
|
|
Amortization of individually insignificant unproved properties
|
1.4
|
|
|
7.0
|
|
|
4.4
|
|
|||
Land and buildings
|
3.0
|
|
|
—
|
|
|
0.8
|
|
|||
Total impairment of properties and equipment
|
$
|
10.0
|
|
|
$
|
161.6
|
|
|
$
|
166.8
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||
|
|
2016 - 2015
|
|
2015 - 2014
|
||||
|
|
(in millions)
|
||||||
Increase in production
|
|
$
|
132.3
|
|
|
$
|
123.4
|
|
Decrease in weighted-average depreciation, depletion and amortization rates
|
|
(18.0
|
)
|
|
(13.1
|
)
|
||
Total increase in DD&A expense related to crude oil and natural gas properties
|
|
$
|
114.3
|
|
|
$
|
110.3
|
|
|
|
Year Ended December 31,
|
||||||||||
Operating Region/Area
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(per Boe)
|
||||||||||
Wattenberg Field
|
|
$
|
19.11
|
|
|
$
|
20.13
|
|
|
$
|
19.26
|
|
Delaware Basin
|
|
8.34
|
|
|
—
|
|
|
—
|
|
|||
Utica Shale
|
|
10.66
|
|
|
10.74
|
|
|
31.19
|
|
|||
Total weighted-average
|
|
18.63
|
|
|
19.44
|
|
|
20.28
|
|
|
|
Payments due by period
|
||||||||||||||||||
|
|
|
|
Less than
|
|
1-3
|
|
3-5
|
|
More than
|
||||||||||
Contractual Obligations and Contingent Commitments
|
|
Total
|
|
1 year
|
|
years
|
|
years
|
|
5 years
|
||||||||||
|
|
(in millions)
|
||||||||||||||||||
Long-term liabilities reflected on the consolidated balance sheet (1)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-term debt (2)
|
|
$
|
1,100
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
900
|
|
|
$
|
200
|
|
Commodity derivative contracts (3)
|
|
81
|
|
|
54
|
|
|
27
|
|
|
—
|
|
|
—
|
|
|||||
Capital leases (4)
|
|
2
|
|
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|||||
Production tax liability
|
|
53
|
|
|
24
|
|
|
29
|
|
|
—
|
|
|
—
|
|
|||||
Asset retirement obligations
|
|
93
|
|
|
10
|
|
|
20
|
|
|
22
|
|
|
41
|
|
|||||
Other liabilities (5)
|
|
7
|
|
|
1
|
|
|
1
|
|
|
2
|
|
|
3
|
|
|||||
|
|
1,336
|
|
|
90
|
|
|
78
|
|
|
924
|
|
|
244
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Commitments, contingencies and other arrangements (6)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest on long-term debt (7)
|
|
537
|
|
|
91
|
|
|
181
|
|
|
169
|
|
|
96
|
|
|||||
Operating leases
|
|
22
|
|
|
3
|
|
|
6
|
|
|
6
|
|
|
7
|
|
|||||
Firm transportation and processing agreements (8)
|
|
187
|
|
|
17
|
|
|
52
|
|
|
49
|
|
|
69
|
|
|||||
|
|
746
|
|
|
111
|
|
|
239
|
|
|
224
|
|
|
172
|
|
|||||
Total
|
|
$
|
2,082
|
|
|
$
|
201
|
|
|
$
|
317
|
|
|
$
|
1,148
|
|
|
$
|
416
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Table does not include deferred income tax liability to taxing authorities of
$143.5 million
, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.
|
(2)
|
Amount presented does not agree with the consolidated balance sheets in that it excludes
$37.5 million
of unamortized debt discount and
$18.6 million
of unamortized debt issuance costs.
|
(3)
|
Represents our gross liability related to the fair value of derivative positions.
|
(4)
|
Short-term capital lease obligations are included in other accrued expenses on the consolidated balance sheets. Long-term capital lease obligations are included in other liabilities on the consolidated balance sheets.
|
(5)
|
Includes deferred compensation to former executive officers and deferred payments related to firm transportation agreements.
|
(6)
|
Table does not include an undrawn
$11.7 million
irrevocable standby letter of credit pending issuance to a transportation service provider. Additionally, the table does not include the annual repurchase obligations to investing partners or termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.
|
(7)
|
Amounts presented include $224.4 million to the holders of our 2022 Senior Notes, $188.7 million to the holders of our 2024 Senior Notes, and $115.2 million payable to the holders of our 2021 Convertible Notes. Amounts also include $11.0 million payable to the participating banks in our revolving credit facility, of which interest of $9.0 million is related to unutilized commitments at a rate of 0.38% per annum, and $0.2 million is related to our undrawn letters of credit.
|
(8)
|
Represents our gross commitment which includes volumes produced by us, purchased from third parties and produced by our affiliated partnerships and other third-party working, royalty and overriding royalty interest owners whose volumes we market on their behalf. This includes anticipated and estimated commitments associated with a new gas processing facility by our primary mid-stream provider. The timing of such payments has been estimated and is subject to change based on the completion of construction and the commencing of operations by the midstream provider.
|
•
|
operating performance and return on capital as compared to our peers;
|
•
|
financial performance of our assets and our valuation without regard to financing methods, capital structure, or historical cost basis;
|
•
|
ability to generate sufficient cash to service our debt obligations and commitments; and
|
•
|
viability of acquisition opportunities and capital investment projects, including the related rate of return.
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Adjusted cash flows from operations:
|
|
|
|
|
|
||||||
Net cash from operating activities
|
$
|
486.3
|
|
|
$
|
411.1
|
|
|
$
|
236.7
|
|
Changes in assets and liabilities
|
(19.5
|
)
|
|
9.7
|
|
|
13.5
|
|
|||
Adjusted cash flows from operations
|
$
|
466.8
|
|
|
$
|
420.8
|
|
|
$
|
250.2
|
|
|
|
|
|
|
|
||||||
Adjusted net income (loss):
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
(245.9
|
)
|
|
$
|
(68.3
|
)
|
|
$
|
155.4
|
|
(Gain) loss on commodity derivative instruments
|
125.6
|
|
|
(203.2
|
)
|
|
(309.3
|
)
|
|||
Net settlements on commodity derivative instruments
|
208.2
|
|
|
239.0
|
|
|
(2.0
|
)
|
|||
Tax effect of above adjustments
|
(124.9
|
)
|
|
(13.6
|
)
|
|
118.2
|
|
|||
Adjusted net income (loss)
|
$
|
(37.0
|
)
|
|
$
|
(46.1
|
)
|
|
$
|
(37.7
|
)
|
|
|
|
|
|
|
||||||
Net income (loss) to adjusted EBITDA:
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
(245.9
|
)
|
|
$
|
(68.3
|
)
|
|
$
|
155.4
|
|
(Gain) loss on commodity derivative instruments, including net settlements
|
125.6
|
|
|
(203.2
|
)
|
|
(309.3
|
)
|
|||
Net settlement (gain) loss on commodity derivative instruments
|
208.2
|
|
|
239.0
|
|
|
(2.0
|
)
|
|||
Interest expense, net
|
61.0
|
|
|
42.8
|
|
|
48.6
|
|
|||
Income tax expense (benefit)
|
(147.2
|
)
|
|
(38.3
|
)
|
|
99.2
|
|
|||
Impairment of properties and equipment
|
10.0
|
|
|
161.6
|
|
|
167.3
|
|
|||
Depreciation, depletion and amortization
|
416.9
|
|
|
303.3
|
|
|
201.7
|
|
|||
Accretion of asset retirement obligations
|
7.0
|
|
|
6.3
|
|
|
3.4
|
|
|||
Adjusted EBITDA
|
$
|
435.6
|
|
|
$
|
443.2
|
|
|
$
|
364.3
|
|
|
|
|
|
|
|
||||||
Cash from operating activities to adjusted EBITDA:
|
|
|
|
|
|
||||||
Net cash from operating activities
|
$
|
486.3
|
|
|
$
|
411.1
|
|
|
$
|
236.7
|
|
Interest expense, net
|
61.0
|
|
|
42.8
|
|
|
48.6
|
|
|||
Stock-based compensation
|
(19.5
|
)
|
|
(20.1
|
)
|
|
(17.5
|
)
|
|||
Amortization of debt discount and issuance costs
|
(16.2
|
)
|
|
(7.0
|
)
|
|
(6.9
|
)
|
|||
Gain on sale of properties and equipment
|
—
|
|
|
0.4
|
|
|
76.0
|
|
|||
Other
|
(56.5
|
)
|
|
6.3
|
|
|
13.9
|
|
|||
Changes in assets and liabilities
|
(19.5
|
)
|
|
9.7
|
|
|
13.5
|
|
|||
Adjusted EBITDA
|
$
|
435.6
|
|
|
$
|
443.2
|
|
|
$
|
364.3
|
|
|
|
|
|
|
|
||||||
PV-10:
|
|
|
|
|
|
||||||
PV-10
|
$
|
1,675.0
|
|
|
$
|
1,337.5
|
|
|
$
|
3,450.1
|
|
Present value of estimated future income tax discounted at 10%
|
(254.4
|
)
|
|
(240.6
|
)
|
|
(1,143.6
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
1,420.6
|
|
|
$
|
1,096.9
|
|
|
$
|
2,306.5
|
|
(1)
|
Approximately 44 percent of the fair value of our commodity derivative assets and 18
percent
of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3).
|
|
Year Ended December 31,
|
||||||
|
2016
|
|
2015
|
||||
Average Index Price:
|
|
|
|
||||
Crude oil (per Bbl)
|
|
|
|
||||
NYMEX
|
$
|
43.32
|
|
|
$
|
48.80
|
|
Natural gas (per MMBtu)
|
|
|
|
||||
NYMEX
|
$
|
2.46
|
|
|
$
|
2.66
|
|
|
|
|
|
||||
Average Sales Price Realized:
|
|
|
|
||||
Excluding net settlements on commodity derivatives
|
|
|
|
||||
Crude oil (per Bbl)
|
$
|
39.96
|
|
|
$
|
40.14
|
|
Natural gas (per Mcf)
|
1.77
|
|
|
2.04
|
|
||
NGLs (per Bbl)
|
11.80
|
|
|
10.72
|
|
Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information
|
||
|
|
|
Financial Statements:
|
|
|
|
||
|
||
Consolidated Statements of Operations - Years Ended December 31, 2
016, 2015 and 2014
|
|
|
Consolidated Statements of Cash Flows - Years Ended December 31, 201
6, 2015 and 2014
|
|
|
Consolidated Statements of Equity - Years Ended December 31, 201
6, 2015 and 2014
|
|
|
|
||
|
|
|
Supplemental Information - Unaudited:
|
|
|
|
||
|
||
|
|
|
Financial Statement Schedule:
|
|
|
|
||
|
|
|
As of December 31,
|
|
2016
|
|
2015
|
||||
Assets
|
|
|
|
|
||||
Current assets:
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
244,100
|
|
|
$
|
850
|
|
Accounts receivable, net
|
|
143,392
|
|
|
104,274
|
|
||
Fair value of derivatives
|
|
8,791
|
|
|
221,659
|
|
||
Prepaid expenses and other current assets
|
|
3,542
|
|
|
5,266
|
|
||
Total current assets
|
|
399,825
|
|
|
332,049
|
|
||
Properties and equipment, net
|
|
4,008,266
|
|
|
1,940,552
|
|
||
Fair value of derivatives
|
|
2,386
|
|
|
44,387
|
|
||
Goodwill
|
|
62,041
|
|
|
—
|
|
||
Other assets
|
|
13,324
|
|
|
53,555
|
|
||
Total Assets
|
|
$
|
4,485,842
|
|
|
$
|
2,370,543
|
|
|
|
|
|
|
||||
Liabilities and Stockholders' Equity
|
|
|
|
|
||||
Liabilities
|
|
|
|
|
||||
Current liabilities:
|
|
|
|
|
||||
Accounts payable
|
|
$
|
66,322
|
|
|
$
|
92,613
|
|
Production tax liability
|
|
24,767
|
|
|
26,524
|
|
||
Fair value of derivatives
|
|
53,595
|
|
|
1,595
|
|
||
Funds held for distribution
|
|
71,339
|
|
|
29,894
|
|
||
Current portion of long-term debt
|
|
—
|
|
|
112,940
|
|
||
Accrued interest payable
|
|
15,930
|
|
|
9,057
|
|
||
Other accrued expenses
|
|
38,625
|
|
|
28,709
|
|
||
Total current liabilities
|
|
270,578
|
|
|
301,332
|
|
||
Long-term debt
|
|
1,043,954
|
|
|
529,437
|
|
||
Deferred income taxes
|
|
400,867
|
|
|
143,452
|
|
||
Asset retirement obligations
|
|
82,612
|
|
|
84,032
|
|
||
Fair value of derivatives
|
|
27,595
|
|
|
695
|
|
||
Other liabilities
|
|
37,482
|
|
|
24,398
|
|
||
Total liabilities
|
|
1,863,088
|
|
|
1,083,346
|
|
||
|
|
|
|
|
||||
Commitments and contingent liabilities
|
|
|
|
|
||||
|
|
|
|
|
||||
Stockholders' equity
|
|
|
|
|
||||
Common shares - par value $0.01 per share, 150,000,000 authorized, 65,704,568 and 40,174,776 issued as of December 31, 2016 and 2015, respectively
|
|
657
|
|
|
402
|
|
||
Additional paid-in capital
|
|
2,489,557
|
|
|
907,382
|
|
||
Retained earnings
|
|
134,208
|
|
|
380,422
|
|
||
Treasury shares - at cost, 28,763 and 20,220 as of December 31, 2016 and 2015, respectively
|
|
(1,668
|
)
|
|
(1,009
|
)
|
||
Total stockholders' equity
|
|
2,622,754
|
|
|
1,287,197
|
|
||
Total Liabilities and Stockholders' Equity
|
|
$
|
4,485,842
|
|
|
$
|
2,370,543
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
||||||
Revenues
|
|
|
|
|
|
|
||||||
Crude oil, natural gas, and NGLs sales
|
|
$
|
497,353
|
|
|
$
|
378,713
|
|
|
$
|
471,413
|
|
Sales from gas marketing
|
|
8,725
|
|
|
10,920
|
|
|
71,571
|
|
|||
Commodity price risk management gain (loss), net of settlements
|
|
(125,681
|
)
|
|
203,183
|
|
|
310,304
|
|
|||
Other income
|
|
2,518
|
|
|
2,510
|
|
|
2,919
|
|
|||
Total revenues
|
|
382,915
|
|
|
595,326
|
|
|
856,207
|
|
|||
Costs, expenses and other
|
|
|
|
|
|
|
||||||
Lease operating expenses
|
|
59,950
|
|
|
56,992
|
|
|
42,402
|
|
|||
Production taxes
|
|
31,410
|
|
|
18,443
|
|
|
25,615
|
|
|||
Transportation, gathering and processing expenses
|
|
18,415
|
|
|
10,151
|
|
|
4,592
|
|
|||
Cost of gas marketing
|
|
10,193
|
|
|
11,717
|
|
|
72,015
|
|
|||
Exploration expense
|
|
4,669
|
|
|
1,102
|
|
|
947
|
|
|||
Impairment of properties and equipment
|
|
9,973
|
|
|
161,620
|
|
|
166,847
|
|
|||
General and administrative expense
|
|
112,470
|
|
|
89,959
|
|
|
123,559
|
|
|||
Depreciation, depletion and amortization
|
|
416,874
|
|
|
303,258
|
|
|
192,528
|
|
|||
Provision for uncollectible notes receivable
|
|
44,038
|
|
|
—
|
|
|
—
|
|
|||
Accretion of asset retirement obligations
|
|
7,080
|
|
|
6,293
|
|
|
3,415
|
|
|||
(Gain) loss on sale of properties and equipment
|
|
(43
|
)
|
|
(385
|
)
|
|
507
|
|
|||
Total cost, expenses and other
|
|
715,029
|
|
|
659,150
|
|
|
632,427
|
|
|||
Income (loss) from operations
|
|
(332,114
|
)
|
|
(63,824
|
)
|
|
223,780
|
|
|||
Interest expense
|
|
(61,972
|
)
|
|
(47,571
|
)
|
|
(47,842
|
)
|
|||
Interest income
|
|
963
|
|
|
4,807
|
|
|
1,290
|
|
|||
Income (loss) before income taxes
|
|
(393,123
|
)
|
|
(106,588
|
)
|
|
177,228
|
|
|||
Income tax benefit (expense)
|
|
147,195
|
|
|
38,308
|
|
|
(69,967
|
)
|
|||
Income (loss) from continuing operations
|
|
(245,928
|
)
|
|
(68,280
|
)
|
|
107,261
|
|
|||
Income from discontinued operations, net of tax
|
|
—
|
|
|
—
|
|
|
48,174
|
|
|||
Net income (loss)
|
|
$
|
(245,928
|
)
|
|
$
|
(68,280
|
)
|
|
$
|
155,435
|
|
|
|
|
|
|
|
|
||||||
Earnings per share:
|
|
|
|
|
|
|
||||||
Basic
|
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
|
$
|
(5.01
|
)
|
|
$
|
(1.74
|
)
|
|
$
|
3.00
|
|
Income from discontinued operations, net of tax
|
|
—
|
|
|
—
|
|
|
1.34
|
|
|||
Basic
|
|
$
|
(5.01
|
)
|
|
$
|
(1.74
|
)
|
|
$
|
4.34
|
|
|
|
|
|
|
|
|
||||||
Diluted
|
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
|
$
|
(5.01
|
)
|
|
$
|
(1.74
|
)
|
|
$
|
2.93
|
|
Income from discontinued operations, net of tax
|
|
—
|
|
|
—
|
|
|
1.31
|
|
|||
Diluted
|
|
$
|
(5.01
|
)
|
|
$
|
(1.74
|
)
|
|
$
|
4.24
|
|
|
|
|
|
|
|
|
||||||
Weighted-average common shares outstanding:
|
|
|
|
|
|
|
||||||
Basic
|
|
49,052
|
|
|
39,153
|
|
|
35,784
|
|
|||
Diluted
|
|
49,052
|
|
|
39,153
|
|
|
36,678
|
|
|||
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
(245,928
|
)
|
|
$
|
(68,280
|
)
|
|
$
|
155,435
|
|
Adjustments to net income (loss) to reconcile to net cash from operating activities:
|
|
|
|
|
|
|
||||||
Net change in fair value of unsettled commodity derivatives
|
|
333,770
|
|
|
35,791
|
|
|
(311,281
|
)
|
|||
Depreciation, depletion and amortization
|
|
416,874
|
|
|
303,258
|
|
|
201,656
|
|
|||
Provision for uncollectible notes receivable
|
|
44,038
|
|
|
—
|
|
|
—
|
|
|||
Impairment of properties and equipment
|
|
9,973
|
|
|
161,620
|
|
|
167,280
|
|
|||
Accretion of asset retirement obligation
|
|
7,080
|
|
|
6,293
|
|
|
3,455
|
|
|||
Stock-based compensation
|
|
19,502
|
|
|
20,068
|
|
|
17,518
|
|
|||
Excess tax benefits from stock-based compensation
|
|
—
|
|
|
(1,361
|
)
|
|
(1,999
|
)
|
|||
Gain from sale of properties and equipment
|
|
(43
|
)
|
|
(385
|
)
|
|
(75,972
|
)
|
|||
Amortization of debt discount and issuance costs
|
|
16,167
|
|
|
7,040
|
|
|
6,938
|
|
|||
Deferred income taxes
|
|
(137,249
|
)
|
|
(41,415
|
)
|
|
88,474
|
|
|||
Other
|
|
2,603
|
|
|
(1,855
|
)
|
|
(1,329
|
)
|
|||
Total adjustments to net income (loss) to reconcile to net cash from operating activities:
|
|
712,715
|
|
|
489,054
|
|
|
94,740
|
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
|
||||||
Accounts receivable
|
|
(32,627
|
)
|
|
24,769
|
|
|
(34,598
|
)
|
|||
Other assets
|
|
2,303
|
|
|
(2,264
|
)
|
|
(3,296
|
)
|
|||
Restricted cash
|
|
—
|
|
|
46
|
|
|
2,214
|
|
|||
Production tax liability
|
|
9,223
|
|
|
(1,629
|
)
|
|
3,358
|
|
|||
Accounts payable and accrued expenses
|
|
(162
|
)
|
|
(30,310
|
)
|
|
21,453
|
|
|||
Funds held for future distribution
|
|
36,510
|
|
|
2,699
|
|
|
(4,372
|
)
|
|||
Other liabilities
|
|
4,229
|
|
|
(3,012
|
)
|
|
1,755
|
|
|||
Total changes in assets and liabilities
|
|
19,476
|
|
|
(9,701
|
)
|
|
(13,486
|
)
|
|||
Net cash from operating activities
|
|
486,263
|
|
|
411,073
|
|
|
236,689
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
|
||||||
Capital expenditures for development of crude oil and natural gas properties
|
|
(436,884
|
)
|
|
(599,546
|
)
|
|
(623,750
|
)
|
|||
Capital expenditures for other properties and equipment
|
|
(3,464
|
)
|
|
(5,122
|
)
|
|
(4,842
|
)
|
|||
Acquisition of crude oil and natural gas properties, net of cash acquired
|
|
(1,073,723
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from sale of properties and equipment, net
|
|
4,945
|
|
|
405
|
|
|
154,457
|
|
|||
Net cash from investing activities
|
|
(1,509,126
|
)
|
|
(604,263
|
)
|
|
(474,135
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
|
||||||
Proceeds from sale of equity, net of issuance costs
|
|
855,074
|
|
|
202,851
|
|
|
—
|
|
|||
Proceeds from senior notes, net of issuance costs
|
|
392,172
|
|
|
—
|
|
|
—
|
|
|||
Proceeds from convertible senior notes, net of issuance costs
|
|
193,935
|
|
|
—
|
|
|
—
|
|
|||
Proceeds from revolving credit facility
|
|
85,000
|
|
|
397,000
|
|
|
263,750
|
|
|||
Repayment of revolving credit facility
|
|
(122,000
|
)
|
|
(416,000
|
)
|
|
(200,000
|
)
|
|||
Redemption of convertible notes
|
|
(115,000
|
)
|
|
—
|
|
|
—
|
|
|||
Payment of debt issuance costs
|
|
(15,556
|
)
|
|
(974
|
)
|
|
(88
|
)
|
|||
Excess tax benefits from stock-based compensation
|
|
—
|
|
|
1,361
|
|
|
1,999
|
|
|||
Purchase of treasury shares
|
|
(6,935
|
)
|
|
(6,056
|
)
|
|
(5,392
|
)
|
|||
Other
|
|
(577
|
)
|
|
(208
|
)
|
|
—
|
|
|||
Net cash from financing activities
|
|
1,266,113
|
|
|
177,974
|
|
|
60,269
|
|
|||
Net change in cash and cash equivalents
|
|
243,250
|
|
|
(15,216
|
)
|
|
(177,177
|
)
|
|||
Cash and cash equivalents, beginning of year
|
|
850
|
|
|
16,066
|
|
|
193,243
|
|
|||
Cash and cash equivalents, end of year
|
|
$
|
244,100
|
|
|
$
|
850
|
|
|
$
|
16,066
|
|
|
|
|
|
|
|
|
||||||
Supplemental cash flow information:
|
|
|
|
|
|
|
||||||
Cash payments for:
|
|
|
|
|
|
|
||||||
Interest, net of capitalized interest
|
|
$
|
43,406
|
|
|
$
|
45,642
|
|
|
$
|
46,809
|
|
Income taxes, net of refunds
|
|
167
|
|
|
10,049
|
|
|
1,800
|
|
|||
Non-cash investing activities:
|
|
|
|
|
|
|
||||||
Issuance of common stock for acquisition of crude oil and natural gas properties related to Delaware Basin acquisition
|
|
690,702
|
|
|
—
|
|
|
—
|
|
|||
Change in accounts payable related to capital expenditures
|
|
(40,448
|
)
|
|
(45,230
|
)
|
|
39,667
|
|
|||
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposal
|
|
4,894
|
|
|
14,030
|
|
|
33,250
|
|
|||
Change in other assets related to sale of properties and equipment
|
|
—
|
|
|
—
|
|
|
39,048
|
|
|||
Purchase of properties and equipment under capital leases
|
|
1,404
|
|
|
1,601
|
|
|
—
|
|
|||
See footnote titled
Business Combinations
for non-cash transactions related to our acquisitions.
|
|
|
|
|
|
Common Stock
|
|
|
|
Treasury Stock
|
|
|
|
|
||||||||||||||||
|
Shares
|
|
Amount
|
|
Additional Paid-in Capital
|
|
Shares
|
|
Amount
|
|
Retained Earnings
|
|
Total Stockholders' Equity
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Balances, January 1, 2014
|
35,675,656
|
|
|
$
|
357
|
|
|
$
|
674,211
|
|
|
(5,508
|
)
|
|
$
|
(241
|
)
|
|
$
|
293,267
|
|
|
$
|
967,594
|
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
155,435
|
|
|
155,435
|
|
|||||
Purchase of treasury shares
|
—
|
|
|
—
|
|
|
—
|
|
|
(97,646
|
)
|
|
(5,392
|
)
|
|
—
|
|
|
(5,392
|
)
|
|||||
Issuance of treasury shares
|
—
|
|
|
—
|
|
|
(4,817
|
)
|
|
83,208
|
|
|
4,817
|
|
|
—
|
|
|
—
|
|
|||||
Retirement of treasury shares
|
(703
|
)
|
|
—
|
|
|
(35
|
)
|
|
703
|
|
|
35
|
|
|
—
|
|
|
—
|
|
|||||
Non-employee directors' deferred compensation plan
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,400
|
)
|
|
(130
|
)
|
|
—
|
|
|
(130
|
)
|
|||||
Issuance of stock awards, net of forfeitures
|
253,032
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|||||
Stock-based compensation expense, including tax impact
|
—
|
|
|
—
|
|
|
19,850
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19,850
|
|
|||||
Balances, December 31, 2014
|
35,927,985
|
|
|
$
|
359
|
|
|
$
|
689,209
|
|
|
(21,643
|
)
|
|
$
|
(911
|
)
|
|
$
|
448,702
|
|
|
$
|
1,137,359
|
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(68,280
|
)
|
|
(68,280
|
)
|
|||||
Issuance pursuant to sale of equity
|
4,002,000
|
|
|
40
|
|
|
202,811
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
202,851
|
|
|||||
Purchase of treasury shares
|
—
|
|
|
—
|
|
|
—
|
|
|
(120,864
|
)
|
|
(6,055
|
)
|
|
—
|
|
|
(6,055
|
)
|
|||||
Issuance of treasury shares
|
—
|
|
|
|
|
(6,206
|
)
|
|
127,159
|
|
|
6,206
|
|
|
—
|
|
|
—
|
|
||||||
Non-employee directors' deferred compensation plan
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,872
|
)
|
|
(249
|
)
|
|
—
|
|
|
(249
|
)
|
|||||
Issuance of stock awards, net of forfeitures
|
237,071
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|||||
Exercise of stock options
|
7,720
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Stock-based compensation expense, including tax impact
|
—
|
|
|
—
|
|
|
21,568
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21,568
|
|
|||||
Balances, December 31, 2015
|
40,174,776
|
|
|
$
|
402
|
|
|
$
|
907,382
|
|
|
(20,220
|
)
|
|
$
|
(1,009
|
)
|
|
$
|
380,422
|
|
|
$
|
1,287,197
|
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(245,928
|
)
|
|
(245,928
|
)
|
|||||
Issuance pursuant to acquisition
|
9,386,768
|
|
|
94
|
|
|
690,608
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
690,702
|
|
|||||
Issuance pursuant to sale of equity
|
15,007,500
|
|
|
150
|
|
|
854,933
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
855,083
|
|
|||||
Issuance pursuant to note conversion
|
792,406
|
|
|
8
|
|
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Convertible debt discount, net of issuance costs and tax
|
—
|
|
|
—
|
|
|
23,518
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23,518
|
|
|||||
Purchase of treasury shares
|
—
|
|
|
—
|
|
|
—
|
|
|
(116,085
|
)
|
|
(6,935
|
)
|
|
—
|
|
|
(6,935
|
)
|
|||||
Issuance of treasury shares
|
(114,697
|
)
|
|
—
|
|
|
(6,661
|
)
|
|
114,697
|
|
|
6,661
|
|
|
—
|
|
|
—
|
|
|||||
Non-employee directors' deferred compensation plan
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,155
|
)
|
|
(385
|
)
|
|
—
|
|
|
(385
|
)
|
|||||
Issuance of stock awards, net of forfeitures
|
411,731
|
|
|
3
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Exercise of stock options
|
46,084
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Stock-based compensation expense
|
—
|
|
|
—
|
|
|
19,502
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19,502
|
|
|||||
Adoption of updated stock-based compensation accounting
|
—
|
|
|
—
|
|
|
286
|
|
|
—
|
|
|
—
|
|
|
(286
|
)
|
|
—
|
|
|||||
Balances, December 31, 2016
|
65,704,568
|
|
|
$
|
657
|
|
|
$
|
2,489,557
|
|
|
(28,763
|
)
|
|
$
|
(1,668
|
)
|
|
$
|
134,208
|
|
|
$
|
2,622,754
|
|
Transportation, pipeline, and other equipment
|
2 - 30 years
|
Buildings
|
20 - 40 years
|
•
|
The primary impact of the adoption was the recognition of excess tax benefits in our provision for income taxes rather than additional paid-in capital, as well as the adjustment in stock-based compensation expense as a result of our changes in forfeiture policy. The new guidance eliminates the requirement to delay the recognition of excess tax benefits until it reduces current taxes payable. We adopted this change on a prospective basis, and recorded unrecognized excess tax benefits amounting to $
1.5 million
, which increased retained earnings in the fourth quarter of 2016.
|
•
|
The new guidance also requires us to record, subsequent to the adoption, excess tax benefits and tax deficiencies in the period they occur. Prior to the adoption, the excess tax benefits would have been recorded as APIC. This change could create future volatility in our effective tax rate depending upon the amount of exercise or vesting activity from our stock awards. Under the new guidance,
|
•
|
The amendment to the minimum statutory withholding tax requirements was adopted on a modified retrospective basis. The adoption had no impact on retained earnings.
|
•
|
In addition, we adopted the presentation of taxes paid related to the net share settlement as a financing activity on the statement of cash flows on a retrospective basis. Adoption had no impact to any of the periods presented in our consolidated cash flows statements since such cash flows have historically been presented as a financing activity.
|
|
Year Ended December 31, 2016
|
||
Acquisition costs:
|
|
||
Cash, net of cash acquired
|
$
|
912,142
|
|
Retirement of seller's debt
|
40,000
|
|
|
Total cash consideration
|
952,142
|
|
|
Common stock, 9.4 million shares
|
690,702
|
|
|
Other purchase price adjustments
|
1,026
|
|
|
Total acquisition costs
|
$
|
1,643,870
|
|
|
|
||
Recognized amounts of identifiable assets acquired and liabilities assumed:
|
|
||
Assets acquired:
|
|
||
Current assets
|
$
|
8,201
|
|
Crude oil and natural gas properties - proved
|
216,000
|
|
|
Crude oil and natural gas properties - unproved
|
1,721,334
|
|
|
Infrastructure, pipeline, and other
|
32,590
|
|
|
Construction in progress
|
12,148
|
|
|
Goodwill
|
62,041
|
|
|
Total assets acquired
|
2,052,314
|
|
|
Liabilities assumed:
|
|
||
Current liabilities
|
(24,844
|
)
|
|
Asset retirement obligations
|
(3,705
|
)
|
|
Deferred tax liabilities, net
|
(379,895
|
)
|
|
Total liabilities assumed
|
(408,444
|
)
|
|
Total identifiable net assets acquired
|
$
|
1,643,870
|
|
|
Years Ended December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands, except per share amounts)
|
||||||
Total revenue
|
$
|
412,746
|
|
|
$
|
598,932
|
|
Net loss
|
$
|
(270,942
|
)
|
|
$
|
(138,904
|
)
|
|
|
|
|
||||
Earnings (loss) per share:
|
|
|
|
||||
Basic and diluted
|
$
|
(4.22
|
)
|
|
$
|
(2.41
|
)
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Properties and equipment, net:
|
|
|
|
||||
Crude oil and natural gas properties
|
|
|
|
||||
Proved
|
$
|
3,499,718
|
|
|
$
|
2,881,189
|
|
Unproved
|
1,874,671
|
|
|
60,498
|
|
||
Total crude oil and natural gas properties
|
5,374,389
|
|
|
2,941,687
|
|
||
Infrastructure, pipeline, and other
|
62,093
|
|
|
30,098
|
|
||
Land and buildings
|
12,165
|
|
|
12,667
|
|
||
Construction in progress
|
122,591
|
|
|
113,115
|
|
||
Properties and equipment, at cost
|
5,571,238
|
|
|
3,097,567
|
|
||
Accumulated DD&A
|
(1,562,972
|
)
|
|
(1,157,015
|
)
|
||
Properties and equipment, net
|
$
|
4,008,266
|
|
|
$
|
1,940,552
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
||||||
Impairment of proved and unproved properties
|
$
|
5,562
|
|
|
$
|
154,608
|
|
|
$
|
161,604
|
|
Amortization of individually insignificant unproved properties
|
1,379
|
|
|
7,012
|
|
|
4,465
|
|
|||
Land and buildings
|
3,032
|
|
|
—
|
|
|
778
|
|
|||
Impairment of properties and equipment
|
9,973
|
|
|
161,620
|
|
|
166,847
|
|
|||
Discontinued operations:
|
|
|
|
|
|
||||||
Impairment of proved and unproved properties
|
—
|
|
|
—
|
|
|
433
|
|
|||
Total discontinued operations
|
—
|
|
|
—
|
|
|
433
|
|
|||
Total impairment of properties and equipment
|
$
|
9,973
|
|
|
$
|
161,620
|
|
|
$
|
167,280
|
|
|
|
|
|
|
|
•
|
For crude oil and natural gas sales, we enter into derivative contracts to protect against price declines in future periods. While we structure these commodity derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price increases in the physical market; and
|
•
|
For gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical commodity derivatives in our gas marketing, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative.
|
•
|
Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty;
|
•
|
Fixed-price commodity swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty;
|
•
|
Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG-basis protection swaps, which had a negative differential to NYMEX for the majority of
2016
, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty; and
|
•
|
Physical sales and purchases are commodity derivatives for fixed-priced physical transactions where we sell or purchase third-party supply at fixed rates. These physical commodity derivatives are offset by financial swaps: for a physical sale the offset is a swap purchase and for a physical purchase the offset is a swap sale.
|
Derivative instruments:
|
|
Consolidated Balance sheet line item
|
|
2016
|
|
2015
|
|||||
|
|
|
|
|
(in thousands)
|
||||||
Derivative assets:
|
Current
|
|
|
|
|
|
|
||||
|
Commodity derivative contracts -
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
$
|
8,239
|
|
|
$
|
221,161
|
|
|
Related to gas marketing
|
|
Fair value of derivatives
|
|
251
|
|
|
441
|
|
||
|
Basis protection derivative contracts -
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
301
|
|
|
57
|
|
||
|
|
|
|
|
8,791
|
|
|
221,659
|
|
||
|
Non-current
|
|
|
|
|
|
|
||||
|
Commodity derivative contracts -
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
1,104
|
|
|
44,292
|
|
||
|
Related to gas marketing
|
|
Fair value of derivatives
|
|
19
|
|
|
51
|
|
||
|
Basis protection derivative contracts -
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
1,263
|
|
|
44
|
|
||
|
|
|
|
|
2,386
|
|
|
44,387
|
|
||
Total derivative assets
|
|
|
|
|
$
|
11,177
|
|
|
$
|
266,046
|
|
|
|
|
|
|
|
|
|
||||
Derivative liabilities:
|
Current
|
|
|
|
|
|
|
||||
|
Commodity derivative contracts -
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
$
|
53,353
|
|
|
$
|
—
|
|
|
Related to gas marketing
|
|
Fair value of derivatives
|
|
212
|
|
|
417
|
|
||
|
Basis protection derivative contracts -
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
30
|
|
|
1,178
|
|
||
|
|
|
|
|
53,595
|
|
|
1,595
|
|
||
|
Non-current
|
|
|
|
|
|
|
||||
|
Commodity derivative contracts -
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
27,581
|
|
|
275
|
|
||
|
Related to gas marketing
|
|
Fair value of derivatives
|
|
14
|
|
|
46
|
|
||
|
Basis protection derivative contracts -
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
—
|
|
|
374
|
|
||
|
|
|
|
|
27,595
|
|
|
695
|
|
||
Total derivative liabilities
|
|
|
|
|
$
|
81,190
|
|
|
$
|
2,290
|
|
|
|
Year Ended December 31,
|
||||||||||
Consolidated statements of operations line item
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(in thousands)
|
||||||||||
Commodity price risk management gain (loss), net -
|
|
|
|
|
|
|
||||||
Net settlements
|
|
$
|
208,103
|
|
|
$
|
238,935
|
|
|
$
|
(837
|
)
|
Net change in fair value of unsettled derivatives
|
|
(333,784
|
)
|
|
(35,752
|
)
|
|
311,141
|
|
|||
Total commodity price risk management gain (loss), net
|
|
$
|
(125,681
|
)
|
|
$
|
203,183
|
|
|
$
|
310,304
|
|
Sales from gas marketing -
|
|
|
|
|
|
|
||||||
Net settlements
|
|
$
|
543
|
|
|
$
|
778
|
|
|
$
|
(208
|
)
|
Net change in fair value of unsettled derivatives
|
|
(676
|
)
|
|
(318
|
)
|
|
364
|
|
|||
Total sales from gas marketing
|
|
$
|
(133
|
)
|
|
$
|
460
|
|
|
$
|
156
|
|
Cost of gas marketing -
|
|
|
|
|
|
|
||||||
Net settlements
|
|
$
|
(483
|
)
|
|
$
|
(745
|
)
|
|
$
|
346
|
|
Net change in fair value of unsettled derivatives
|
|
690
|
|
|
279
|
|
|
(451
|
)
|
|||
Total cost of gas marketing
|
|
$
|
207
|
|
|
$
|
(466
|
)
|
|
$
|
(105
|
)
|
|
|
|
|
|
|
|
As of December 31, 2016
|
|
Derivative instruments, recorded in consolidated balance sheet, gross
|
|
Effect of master netting agreements
|
|
Derivative instruments, net
|
||||||
|
|
(in thousands)
|
||||||||||
Asset derivatives:
|
|
|
|
|
|
|
||||||
Derivative instruments, at fair value
|
|
$
|
11,177
|
|
|
$
|
(10,930
|
)
|
|
$
|
247
|
|
|
|
|
|
|
|
|
||||||
Liability derivatives:
|
|
|
|
|
|
|
||||||
Derivative instruments, at fair value
|
|
$
|
81,190
|
|
|
$
|
(10,930
|
)
|
|
$
|
70,260
|
|
|
|
|
|
|
|
|
As of December 31, 2015
|
|
Derivative instruments, recorded in consolidated balance sheet, gross
|
|
Effect of master netting agreements
|
|
Derivative instruments, net
|
||||||
|
|
(in thousands)
|
||||||||||
Asset derivatives:
|
|
|
|
|
|
|
||||||
Derivative instruments, at fair value
|
|
$
|
266,046
|
|
|
$
|
(1,921
|
)
|
|
$
|
264,125
|
|
|
|
|
|
|
|
|
||||||
Liability derivatives:
|
|
|
|
|
|
|
||||||
Derivative instruments, at fair value
|
|
$
|
2,290
|
|
|
$
|
(1,921
|
)
|
|
$
|
369
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
||||||||||||||||||||||
|
2016
|
|
2015
|
||||||||||||||||||||
|
Significant Other
Observable Inputs (Level 2) |
|
Significant
Unobservable Inputs (Level 3) |
|
Total
|
|
Significant Other
Observable Inputs (Level 2) |
|
Significant
Unobservable Inputs (Level 3) |
|
Total
|
||||||||||||
|
(in thousands)
|
||||||||||||||||||||||
Total assets
|
$
|
6,350
|
|
|
$
|
4,827
|
|
|
$
|
11,177
|
|
|
$
|
174,758
|
|
|
$
|
91,288
|
|
|
$
|
266,046
|
|
Total liabilities
|
66,789
|
|
|
14,401
|
|
|
81,190
|
|
|
2,290
|
|
|
—
|
|
|
2,290
|
|
||||||
Net asset (liability)
|
$
|
(60,439
|
)
|
|
$
|
(9,574
|
)
|
|
$
|
(70,013
|
)
|
|
$
|
172,468
|
|
|
$
|
91,288
|
|
|
$
|
263,756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
|
||||||
Fair value of Level 3 instruments, net asset beginning of period
|
|
$
|
91,288
|
|
|
$
|
62,356
|
|
|
$
|
1,111
|
|
Changes in fair value included in consolidated statement of operations line item:
|
|
|
|
|
|
|
||||||
Commodity price risk management gain (loss), net
|
|
(28,530
|
)
|
|
65,018
|
|
|
62,003
|
|
|||
Sales from gas marketing
|
|
(20
|
)
|
|
146
|
|
|
(22
|
)
|
|||
Settlements included in statement of operations line items:
|
|
|
|
|
|
|
||||||
Commodity price risk management gain (loss), net
|
|
(72,242
|
)
|
|
(36,169
|
)
|
|
(737
|
)
|
|||
Sales from gas marketing
|
|
(70
|
)
|
|
(63
|
)
|
|
1
|
|
|||
Fair value of Level 3 instruments, net asset (liability) end of period
|
|
$
|
(9,574
|
)
|
|
$
|
91,288
|
|
|
$
|
62,356
|
|
|
|
|
|
|
|
|
||||||
Net change in fair value of Level 3 unsettled derivatives included in statement of operations line item:
|
|
|
|
|
|
|
||||||
Commodity price risk management gain (loss), net
|
|
$
|
(12,905
|
)
|
|
$
|
43,540
|
|
|
$
|
15,632
|
|
Sales from gas marketing
|
|
—
|
|
|
—
|
|
|
3
|
|
|||
Total
|
|
$
|
(12,905
|
)
|
|
$
|
43,540
|
|
|
$
|
15,635
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value
|
|
% of Par
|
|||
|
(in millions)
|
|
|
|||
Senior notes:
|
|
|
|
|||
2021 Convertible Notes
|
$
|
220.2
|
|
|
110.1
|
%
|
2024 Senior Notes
|
408.0
|
|
|
102.0
|
%
|
|
2022 Senior Notes
|
535.0
|
|
|
107.0
|
%
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
|
|
|
|
||||
Crude oil, natural gas and NGLs sales
|
$
|
97,520
|
|
|
$
|
41,873
|
|
Joint interest billings
|
20,118
|
|
|
35,017
|
|
||
Derivative counterparties
|
10,266
|
|
|
24,437
|
|
||
Income tax receivable
|
11,505
|
|
|
—
|
|
||
Insurance reimbursement
|
—
|
|
|
879
|
|
||
Other
|
6,173
|
|
|
4,077
|
|
||
Allowance for doubtful accounts
|
(2,190
|
)
|
|
(2,009
|
)
|
||
Accounts receivable, net
|
$
|
143,392
|
|
|
$
|
104,274
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|||||||
Customer
|
|
2016
|
|
2015
|
|
2014
|
|||
|
|
|
|
|
|
|
|||
Suncor Energy Marketing, Inc.
|
|
22.3
|
%
|
|
14.3
|
%
|
|
19.7
|
%
|
DCP Midstream, LP
|
|
20.2
|
%
|
|
13.2
|
%
|
|
15.1
|
%
|
Aka Energy Group, LLC
|
|
13.4
|
%
|
|
—
|
%
|
|
—
|
%
|
Concord Energy, LLC
|
|
13.4
|
%
|
|
23.2
|
%
|
|
18.3
|
%
|
Bridger Energy, LLC
|
|
11.5
|
%
|
|
—
|
%
|
|
—
|
%
|
Shell Trading Company
|
|
—
|
%
|
|
13.8
|
%
|
|
—
|
%
|
Teppco Crude Oil, LLC
|
|
—
|
%
|
|
—
|
%
|
|
12.9
|
%
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Principal and PIK Interest outstanding at beginning of period
|
$
|
43,069
|
|
|
$
|
39,707
|
|
PIK Interest
|
969
|
|
|
3,362
|
|
||
Principal and PIK Interest outstanding at end of period
|
44,038
|
|
|
43,069
|
|
||
Allowance for uncollectible notes receivable
|
(44,038
|
)
|
|
—
|
|
||
Note receivable, net
|
$
|
—
|
|
|
$
|
43,069
|
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
|
|
|
|
||||
Employee benefits
|
$
|
22,282
|
|
|
$
|
17,774
|
|
Asset retirement obligations
|
9,775
|
|
|
5,460
|
|
||
Environmental expenses
|
3,238
|
|
|
4,143
|
|
||
Other
|
3,330
|
|
|
1,332
|
|
||
Other accrued expenses
|
$
|
38,625
|
|
|
$
|
28,709
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Current:
|
|
|
|
|
|
||||||
Federal
|
$
|
9,646
|
|
|
$
|
(2,944
|
)
|
|
$
|
(1,514
|
)
|
State
|
300
|
|
|
(163
|
)
|
|
966
|
|
|||
Total current income tax benefit (expense)
|
9,946
|
|
|
(3,107
|
)
|
|
(548
|
)
|
|||
Deferred:
|
|
|
|
|
|
||||||
Federal
|
118,427
|
|
|
37,352
|
|
|
(60,698
|
)
|
|||
State
|
18,822
|
|
|
4,063
|
|
|
(8,721
|
)
|
|||
Total deferred income tax benefit (expense)
|
137,249
|
|
|
41,415
|
|
|
(69,419
|
)
|
|||
Income tax benefit (expense) from continuing operations
|
$
|
147,195
|
|
|
$
|
38,308
|
|
|
$
|
(69,967
|
)
|
|
|
|
|
|
|
|
Year Ended December, 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
|
|
|
|
|
|
|||
Statutory tax rate
|
35.0
|
%
|
|
35.0
|
%
|
|
35.0
|
%
|
State income tax, net
|
2.6
|
|
|
2.7
|
|
|
2.8
|
|
Effect of state income tax rate changes
|
0.6
|
|
|
(0.3
|
)
|
|
—
|
|
Percentage depletion
|
—
|
|
|
0.3
|
|
|
(0.3
|
)
|
Non-deductible compensation
|
(0.5
|
)
|
|
(1.2
|
)
|
|
0.7
|
|
Excess tax benefits from stock-based compensation
|
0.4
|
|
|
—
|
|
|
—
|
|
Other
|
(0.7
|
)
|
|
(0.6
|
)
|
|
1.3
|
|
Effective tax rate
|
37.4
|
%
|
|
35.9
|
%
|
|
39.5
|
%
|
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Deferred tax assets:
|
|
|
|
||||
Deferred compensation
|
$
|
9,338
|
|
|
$
|
13,104
|
|
Asset retirement obligations
|
34,359
|
|
|
34,101
|
|
||
Federal NOL carryforward
|
29,988
|
|
|
—
|
|
||
State NOL and tax credit carryforwards, net
|
5,189
|
|
|
3,376
|
|
||
Alternative minimum tax - credit carryforward
|
5,184
|
|
|
2,812
|
|
||
Allowance for note receivable
|
17,292
|
|
|
—
|
|
||
Net change in fair value of unsettled derivatives
|
26,262
|
|
|
—
|
|
||
Other
|
4,716
|
|
|
3,412
|
|
||
Total gross deferred tax assets
|
132,328
|
|
|
56,805
|
|
||
|
|
|
|
||||
Deferred tax liabilities:
|
|
|
|
||||
Properties and equipment
|
518,964
|
|
|
99,191
|
|
||
Net change in fair value of unsettled derivatives
|
—
|
|
|
100,369
|
|
||
Convertible debt
|
14,231
|
|
|
697
|
|
||
Total gross deferred tax liabilities
|
533,195
|
|
|
200,257
|
|
||
Net deferred tax liability
|
$
|
400,867
|
|
|
$
|
143,452
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Senior notes:
|
|
|
|
||||
1.125% Convertible Notes due 2021:
|
|
|
|
||||
Principal amount
|
$
|
200,000
|
|
|
$
|
—
|
|
Unamortized discount
|
(37,475
|
)
|
|
—
|
|
||
Unamortized debt issuance costs
|
(4,584
|
)
|
|
—
|
|
||
1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs
|
157,941
|
|
|
—
|
|
||
|
|
|
|
||||
6.125% Senior Notes due 2024:
|
|
|
|
||||
Principal amount
|
400,000
|
|
|
—
|
|
||
Unamortized debt issuance costs
|
(7,544
|
)
|
|
—
|
|
||
6.125% Senior Notes due 2024, net of unamortized debt issuance costs
|
392,456
|
|
|
—
|
|
||
|
|
|
|
||||
7.75% Senior notes due 2022:
|
|
|
|
||||
Principal amount
|
500,000
|
|
|
500,000
|
|
||
Unamortized debt issuance costs
|
(6,443
|
)
|
|
(7,563
|
)
|
||
7.75% Senior notes due 2022, net of unamortized debt issuance costs
|
493,557
|
|
|
492,437
|
|
||
|
|
|
|
||||
3.25% Convertible senior notes due 2016:
|
|
|
|
||||
Principal amount
|
—
|
|
|
115,000
|
|
||
Unamortized discount
|
—
|
|
|
(1,852
|
)
|
||
Unamortized debt issuance costs
|
—
|
|
|
(208
|
)
|
||
3.25% Convertible senior notes due 2016, net of unamortized discount and debt issuance costs
|
—
|
|
|
112,940
|
|
||
Total senior notes
|
1,043,954
|
|
|
605,377
|
|
||
|
|
|
|
||||
Revolving credit facility
|
—
|
|
|
37,000
|
|
||
Total debt, net of unamortized discount and debt issuance costs
|
1,043,954
|
|
|
642,377
|
|
||
Less current portion of long-term debt
|
—
|
|
|
112,940
|
|
||
Long-term debt
|
$
|
1,043,954
|
|
|
$
|
529,437
|
|
|
|
As of December 31,
|
||||||
|
|
2016
|
|
2015
|
||||
|
|
(in thousands)
|
||||||
Vehicles
|
|
$
|
2,975
|
|
|
$
|
1,601
|
|
Accumulated depreciation
|
|
(776
|
)
|
|
(211
|
)
|
||
|
|
$
|
2,199
|
|
|
$
|
1,390
|
|
For the Twelve Months Ending December 31,
|
|
Amount
|
||
|
|
(in thousands)
|
||
2017
|
|
$
|
914
|
|
2018
|
|
1,099
|
|
|
2019
|
|
560
|
|
|
|
|
2,573
|
|
|
Less executory cost
|
|
(96
|
)
|
|
Less amount representing interest
|
|
(263
|
)
|
|
Present value of minimum lease payments
|
|
$
|
2,214
|
|
|
|
|
|
|
Short-term capital lease obligations
|
|
$
|
699
|
|
Long-term capital lease obligations
|
|
1,515
|
|
|
|
|
$
|
2,214
|
|
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
|
|
|
|
||||
Balance at beginning of period
|
$
|
89,492
|
|
|
$
|
73,855
|
|
Obligations incurred with development activities and assumed with acquisitions
|
4,894
|
|
|
2,373
|
|
||
Accretion expense
|
7,080
|
|
|
6,293
|
|
||
Revisions in estimated cash flows
|
—
|
|
|
11,658
|
|
||
Obligations discharged with disposal of properties and asset retirements
|
(9,079
|
)
|
|
(4,687
|
)
|
||
Balance at end of period
|
92,387
|
|
|
89,492
|
|
||
Less current portion
|
(9,775
|
)
|
|
(5,460
|
)
|
||
Long-term portion
|
$
|
82,612
|
|
|
$
|
84,032
|
|
|
|
|
|
|
|
Year Ending December 31,
|
|
|
|
|
||||||||||||||||||||
Area
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021 and
Through Expiration |
|
Total
|
|
Expiration
Date |
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Natural gas (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Wattenberg Field (1)
|
|
—
|
|
|
2,300
|
|
|
17,125
|
|
|
18,300
|
|
|
86,700
|
|
|
124,425
|
|
|
September 30, 2025
|
||||||
Gas Marketing segment
|
|
7,117
|
|
|
7,117
|
|
|
7,117
|
|
|
7,136
|
|
|
11,550
|
|
|
40,037
|
|
|
August 31, 2022
|
||||||
Utica Shale
|
|
2,738
|
|
|
2,738
|
|
|
2,738
|
|
|
2,745
|
|
|
7,064
|
|
|
18,023
|
|
|
July 22, 2023
|
||||||
Total
|
|
9,855
|
|
|
12,155
|
|
|
26,980
|
|
|
28,181
|
|
|
105,314
|
|
|
182,485
|
|
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Crude oil (MBbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Wattenberg Field
|
|
2,413
|
|
|
2,413
|
|
|
2,413
|
|
|
1,204
|
|
|
—
|
|
|
8,443
|
|
|
June 30, 2020
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Dollar commitment (in thousands)
|
|
$
|
17,158
|
|
|
$
|
18,626
|
|
|
$
|
33,221
|
|
|
$
|
27,430
|
|
|
$
|
89,896
|
|
|
$
|
186,331
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
In December 2016, in anticipation of our future drilling activities in the Wattenberg Field, we entered into a facilities expansion agreement with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities. The midstream provider is expected to construct a new 200 MMcfd cryogenic plant. We will be bound to the volume requirements in this agreement on the first day of the calendar month after the actual in-service date of the plant, which in the above table is estimated to be September 30, 2018. The agreement requires a baseline volume commitment of current sales volumes to this midstream provider and an incremental volume commitment of
50
MMcfd for seven years, of which we may be required to pay a shortfall fee for any volumes under the
50
MMcfd incremental commitment. Any shortfall of this volume commitment may be offset, in part, by additional third party producers’ volumes sold to the midstream provider when a certain total volume is achieved. We are also required for the first three years of the contract to guarantee a certain target profit margin to the midstream provider on these volumes sold. Under our current drilling plans, we expect to meet both the baseline and incremental volume commitments. Using the NYMEX forward pricing strip at December 31, 2016, the target profit margin would be achieved without an additional payment from us.
|
|
|
Year Ending December 31,
|
|
|
|
|
||||||||||||||||||||||
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
|
Total
|
||||||||||||||
|
|
(in thousands)
|
||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Minimum Lease Payments
|
|
$
|
3,056
|
|
|
$
|
3,041
|
|
|
$
|
3,033
|
|
|
$
|
3,093
|
|
|
$
|
3,154
|
|
|
$
|
6,786
|
|
|
$
|
22,163
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Date
|
|
Shares Issued
|
|
Price per Share
|
|
Net Proceeds
|
|||||
|
|
|
|
|
|
(in millions)
|
|||||
September 2016
|
|
9,085,000
|
|
|
$
|
61.51
|
|
|
$
|
558.5
|
|
March 2016
|
|
5,922,500
|
|
|
50.11
|
|
|
296.6
|
|
||
March 2015
|
|
4,002,000
|
|
|
50.73
|
|
|
202.9
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
|
||||||
Stock-based compensation expense
|
|
$
|
19,502
|
|
|
$
|
20,068
|
|
|
$
|
17,518
|
|
Income tax benefit
|
|
(7,296
|
)
|
|
(7,636
|
)
|
|
(5,955
|
)
|
|||
Net stock-based compensation expense
|
|
$
|
12,206
|
|
|
$
|
12,432
|
|
|
$
|
11,563
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
|
|
|
|
||||||
Expected term of award
|
6.0 years
|
|
|
5.2 years
|
|
|
6.0 years
|
|
|||
Risk-free interest rate
|
1.8
|
%
|
|
1.4
|
%
|
|
2.1
|
%
|
|||
Expected volatility
|
54.5
|
%
|
|
58.0
|
%
|
|
65.6
|
%
|
|||
Weighted-average grant date fair value per share
|
$
|
26.96
|
|
|
$
|
22.23
|
|
|
$
|
29.96
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||||||||||||||||||||||||||
|
Number of
SARs |
|
Weighted-Average
Exercise Price |
|
Average Remaining Contractual
Term (in years) |
|
Aggregate Intrinsic
Value (in thousands) |
|
Number of
SARs |
|
Weighted-Average
Exercise Price |
|
Aggregate Intrinsic
Value (in thousands) |
|
Number of
SARs |
|
Weighted-Average
Exercise Price |
|
Aggregate Intrinsic
Value (in thousands) |
||||||||||||||||
Outstanding beginning of year, January 1,
|
326,453
|
|
|
$
|
38.99
|
|
|
7.3
|
|
|
$
|
4,697
|
|
|
279,011
|
|
|
$
|
38.77
|
|
|
$
|
1,472
|
|
|
190,763
|
|
|
$
|
33.77
|
|
|
$
|
3,711
|
|
Awarded
|
58,709
|
|
|
51.63
|
|
|
—
|
|
|
—
|
|
|
68,274
|
|
|
39.63
|
|
|
—
|
|
|
88,248
|
|
|
49.57
|
|
|
—
|
|
||||||
Exercised
|
(141,084
|
)
|
|
40.16
|
|
|
—
|
|
|
2,770
|
|
|
(20,832
|
)
|
|
38.05
|
|
|
473
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Outstanding at December 31,
|
244,078
|
|
|
41.36
|
|
|
6.9
|
|
|
7,620
|
|
|
326,453
|
|
|
38.99
|
|
|
4,697
|
|
|
279,011
|
|
|
38.77
|
|
|
1,472
|
|
||||||
Exercisable at December 31,
|
174,919
|
|
|
38.72
|
|
|
6.3
|
|
|
5,924
|
|
|
222,489
|
|
|
37.70
|
|
|
3,489
|
|
|
139,334
|
|
|
36.27
|
|
|
982
|
|
|
Shares
|
|
Weighted-Average
Grant Date Fair Value |
|||
|
|
|
|
|||
Non-vested at December 31, 2015
|
525,081
|
|
|
$
|
50.23
|
|
Granted
|
290,010
|
|
|
58.52
|
|
|
Vested
|
(317,034
|
)
|
|
48.61
|
|
|
Forfeited
|
(18,415
|
)
|
|
56.10
|
|
|
Non-vested at December 31, 2016
|
479,642
|
|
|
56.09
|
|
|
|
|
|
|
|
As of/Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands, except per share data)
|
||||||||||
|
|
|
|
|
|
||||||
Total intrinsic value of time-based awards vested
|
$
|
18,973
|
|
|
$
|
17,077
|
|
|
$
|
18,278
|
|
Total intrinsic value of time-based awards non-vested
|
34,812
|
|
|
28,029
|
|
|
23,290
|
|
|||
Market price per common share as of December 31,
|
72.58
|
|
|
53.38
|
|
|
41.27
|
|
|||
Weighted-average grant date fair value per share
|
58.52
|
|
|
48.88
|
|
|
56.45
|
|
|
|
Year Ended December 31,
|
||||||
|
|
2016
|
|
2015
|
||||
|
|
|
|
|
||||
Expected term of award
|
|
3 years
|
|
|
3 years
|
|
||
Risk-free interest rate
|
|
1.2
|
%
|
|
0.9
|
%
|
||
Expected volatility
|
|
52.3
|
%
|
|
53.0
|
%
|
||
Weighted-average grant date fair value per share
|
|
$
|
72.54
|
|
|
$
|
66.16
|
|
|
|
Shares
|
|
Weighted-Average
Grant Date Fair Value per Share |
|||
|
|
|
|
|
|||
Non-vested at December 31, 2015
|
|
71,549
|
|
|
$
|
63.60
|
|
Granted
|
|
24,280
|
|
|
72.54
|
|
|
Vested
|
|
(47,409
|
)
|
|
66.78
|
|
|
Non-vested at December 31, 2016
|
|
48,420
|
|
|
64.97
|
|
|
|
|
|
|
|
|
As of/Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands, except per share data)
|
||||||||||
|
|
|
|
|
|
||||||
Total intrinsic value of market-based awards vested
|
$
|
6,562
|
|
|
$
|
4,293
|
|
|
$
|
1,260
|
|
Total intrinsic value of market-based awards non-vested
|
3,514
|
|
|
3,819
|
|
|
3,455
|
|
|||
Market price per common share as of December 31,
|
72.58
|
|
|
53.38
|
|
|
41.27
|
|
|||
Weighted-average grant date fair value per share
|
72.54
|
|
|
66.16
|
|
|
56.87
|
|
|
Year Ended December 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
|
(in thousands)
|
|||||||
|
|
|
|
|
|
|||
Weighted-average common shares outstanding - basic
|
49,052
|
|
|
39,153
|
|
|
35,784
|
|
Dilutive effect of:
|
|
|
|
|
|
|||
Restricted stock
|
—
|
|
|
—
|
|
|
279
|
|
Convertible notes
|
—
|
|
|
—
|
|
|
564
|
|
Other equity-based awards
|
—
|
|
|
—
|
|
|
51
|
|
Weighted-average common shares and equivalents outstanding - diluted
|
49,052
|
|
|
39,153
|
|
|
36,678
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
|
(in thousands)
|
|||||||
|
|
|
|
|
|
|||
Weighted-average common share equivalents excluded from diluted earnings
|
|
|
|
|
|
|||
per share due to their anti-dilutive effect:
|
|
|
|
|
|
|||
Restricted stock
|
689
|
|
|
831
|
|
|
8
|
|
Convertible notes
|
292
|
|
|
562
|
|
|
—
|
|
Other equity-based awards
|
109
|
|
|
101
|
|
|
26
|
|
Total anti-dilutive common share equivalents
|
1,090
|
|
|
1,494
|
|
|
34
|
|
|
|
|
|
|
|
|
|
|
||
Consolidated statements of operations - discontinued operations
|
|
Year Ended December 31, 2014
|
||
|
|
(in thousands)
|
||
Revenues
|
|
|
||
Crude oil, natural gas and NGLs sales
|
|
$
|
24,149
|
|
Commodity price risk management loss, net
|
|
(1,085
|
)
|
|
Other income
|
|
48
|
|
|
Total revenues
|
|
23,112
|
|
|
|
|
|
||
Costs, expenses and other
|
|
|
||
Lease operating expenses
|
|
1,280
|
|
|
Production taxes
|
|
1,579
|
|
|
Transportation, gathering and processing expenses
|
|
3,536
|
|
|
Impairment of properties and equipment
|
|
433
|
|
|
Depreciation, depletion and amortization
|
|
9,128
|
|
|
Other
|
|
4,170
|
|
|
Gain on sale of properties and equipment
|
|
(76,479
|
)
|
|
Total costs, expenses and other
|
|
(56,353
|
)
|
|
|
|
|
||
Interest expense
|
|
(2,222
|
)
|
|
Interest income
|
|
194
|
|
|
Income from discontinued operations
|
|
77,437
|
|
|
Provision for income taxes
|
|
(29,263
|
)
|
|
Income from discontinued operations, net of tax
|
|
$
|
48,174
|
|
|
|
|
Supplemental cash flows information - discontinued operations
|
|
Year Ended December 31, 2014
|
||
|
|
(in thousands)
|
||
Cash flows from investing activities:
|
|
|
||
Capital expenditures
|
|
$
|
(17,253
|
)
|
|
|
|
||
Significant non-cash investing items:
|
|
|
||
Change in accounts payable related to purchases of properties and equipment
|
|
(5,727
|
)
|
|
2016
|
|
2015
|
—
|
|
2014
|
||||||
|
(in thousands)
|
|||||||||||
Year Ended December 31,
|
|
|
|
|
|
|||||||
Segment revenues:
|
|
|
|
|
|
|||||||
Oil and gas exploration and production
|
$
|
374,190
|
|
|
$
|
584,406
|
|
|
$
|
784,636
|
|
|
Gas marketing
|
8,725
|
|
|
10,920
|
|
|
71,571
|
|
||||
Total revenues
|
$
|
382,915
|
|
|
$
|
595,326
|
|
|
$
|
856,207
|
|
|
|
|
|
|
|
|
|||||||
Segment income (loss) before income taxes:
|
|
|
|
|
|
|||||||
Oil and gas exploration and production
|
$
|
(170,370
|
)
|
|
$
|
31,429
|
|
|
$
|
344,149
|
|
|
Gas marketing
|
(1,468
|
)
|
|
(797
|
)
|
|
(445
|
)
|
||||
Unallocated
|
(221,285
|
)
|
|
(137,220
|
)
|
|
(166,476
|
)
|
||||
Income (loss) before income taxes
|
$
|
(393,123
|
)
|
|
$
|
(106,588
|
)
|
|
$
|
177,228
|
|
|
|
|
|
|
|
|
|||||||
Expenditures for segment long-lived assets:
|
|
|
|
|
|
|||||||
Oil and gas exploration and production
|
$
|
436,884
|
|
|
$
|
599,617
|
|
|
$
|
623,912
|
|
|
Acquisition of crude oil and natural gas properties, net of cash acquired
|
1,073,723
|
|
|
—
|
|
|
—
|
|
||||
Unallocated
|
3,464
|
|
|
5,051
|
|
|
4,680
|
|
||||
Total
|
$
|
1,514,071
|
|
|
$
|
604,668
|
|
|
$
|
628,592
|
|
|
|
|
|
|
|
|
|||||||
As of December 31,
|
|
|
|
|
|
|||||||
Segment assets:
|
|
|
|
|
|
|||||||
Oil and gas exploration and production
|
$
|
4,451,510
|
|
|
$
|
2,294,288
|
|
|
|
|||
Gas marketing
|
4,329
|
|
|
4,217
|
|
|
|
|||||
Unallocated
|
30,003
|
|
|
72,038
|
|
|
|
|||||
Total assets
|
$
|
4,485,842
|
|
|
$
|
2,370,543
|
|
|
|
|||
|
|
|
|
|
|
|
|
Average Benchmark Prices
|
||||||||||
As of December 31,
|
|
Crude Oil
(per Bbl)
|
|
Natural Gas
(per Mcf)
|
|
NGLs
(per Bbl)
|
||||||
|
|
|
|
|
|
|
||||||
2016
|
|
$
|
42.75
|
|
|
$
|
2.48
|
|
|
$
|
42.75
|
|
2015
|
|
50.28
|
|
|
2.59
|
|
|
50.28
|
|
|||
2014
|
|
94.99
|
|
|
4.35
|
|
|
94.99
|
|
|
|
Price Used to Estimate Reserves*
|
||||||||||
As of December 31,
|
|
Crude Oil
(per Bbl)
|
|
Natural Gas
(per Mcf)
|
|
NGLs
(per Bbl)
|
||||||
|
|
|
|
|
|
|
||||||
2016
|
|
$
|
38.67
|
|
|
$
|
1.85
|
|
|
$
|
11.97
|
|
2015
|
|
42.10
|
|
|
2.05
|
|
|
12.23
|
|
|||
2014
|
|
84.65
|
|
|
3.92
|
|
|
32.27
|
|
*
|
These prices are based on the index prices and are net of basin differentials, any transportation fees, contractual adjustments, and any Btu adjustments we experienced for the respective commodity.
|
|
Crude Oil, Condensate (MBbls)
|
|
Natural Gas
(MMcf)
|
|
NGLs
(MBbls)
|
|
Total
(MBoe)
|
||||
Proved Reserves:
|
|
|
|
|
|
|
|
||||
Proved reserves, January 1, 2014 (1)
|
93,830
|
|
|
739,640
|
|
|
48,671
|
|
|
265,774
|
|
Revisions of previous estimates
|
(29,777
|
)
|
|
(149,064
|
)
|
|
(10,204
|
)
|
|
(64,825
|
)
|
Extensions, discoveries and other additions, including infill reserves in an existing proved field
|
40,792
|
|
|
202,957
|
|
|
23,411
|
|
|
98,029
|
|
Acquisition of reserves
|
5
|
|
|
43
|
|
|
5
|
|
|
17
|
|
Dispositions
|
(13
|
)
|
|
(237,306
|
)
|
|
(8
|
)
|
|
(39,572
|
)
|
Production
|
(4,322
|
)
|
|
(19,298
|
)
|
|
(1,756
|
)
|
|
(9,294
|
)
|
Proved reserves, December 31, 2014
|
100,515
|
|
|
536,972
|
|
|
60,119
|
|
|
250,129
|
|
Revisions of previous estimates
|
(43,268
|
)
|
|
(154,775
|
)
|
|
(24,407
|
)
|
|
(93,471
|
)
|
Extensions, discoveries and other additions, including infill reserves in an existing proved field
|
48,707
|
|
|
311,709
|
|
|
30,835
|
|
|
131,494
|
|
Acquisition of reserves
|
17
|
|
|
215
|
|
|
23
|
|
|
76
|
|
Dispositions
|
(12
|
)
|
|
(82
|
)
|
|
(8
|
)
|
|
(34
|
)
|
Production
|
(6,984
|
)
|
|
(33,302
|
)
|
|
(2,835
|
)
|
|
(15,369
|
)
|
Proved reserves, December 31, 2015
|
98,975
|
|
|
660,737
|
|
|
63,727
|
|
|
272,825
|
|
Revisions of previous estimates
|
(22,097
|
)
|
|
(80,426
|
)
|
|
(7,130
|
)
|
|
(42,631
|
)
|
Extensions, discoveries and other additions
|
494
|
|
|
4,094
|
|
|
355
|
|
|
1,531
|
|
Acquisition of reserves
|
50,126
|
|
|
305,224
|
|
|
32,586
|
|
|
133,583
|
|
Dispositions
|
(601
|
)
|
|
(4,202
|
)
|
|
(424
|
)
|
|
(1,725
|
)
|
Production
|
(8,728
|
)
|
|
(51,730
|
)
|
|
(4,826
|
)
|
|
(22,176
|
)
|
Proved reserves, December 31, 2016
|
118,169
|
|
|
833,697
|
|
|
84,288
|
|
|
341,407
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves, as of:
|
|
|
|
|
|
|
|
||||
December 31, 2014
|
26,798
|
|
|
186,633
|
|
|
17,002
|
|
|
74,905
|
|
December 31, 2015
|
26,257
|
|
|
175,367
|
|
|
15,011
|
|
|
70,496
|
|
December 31, 2016
|
30,013
|
|
|
264,452
|
|
|
24,196
|
|
|
98,284
|
|
Proved Undeveloped Reserves, as of:
|
|
|
|
|
|
|
|
||||
December 31, 2014
|
73,717
|
|
|
350,339
|
|
|
43,117
|
|
|
175,224
|
|
December 31, 2015
|
72,718
|
|
|
485,370
|
|
|
48,716
|
|
|
202,329
|
|
December 31, 2016
|
88,156
|
|
|
569,245
|
|
|
60,092
|
|
|
243,122
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Revenue:
|
|
|
|
|
|
||||||
Crude oil, natural gas and NGLs sales
|
$
|
497,353
|
|
|
$
|
378,713
|
|
|
$
|
495,562
|
|
Commodity price risk management gain (loss), net
|
(125,681
|
)
|
|
203,183
|
|
|
309,219
|
|
|||
|
371,672
|
|
|
581,896
|
|
|
804,781
|
|
|||
Expenses:
|
|
|
|
|
|
||||||
Lease operating expenses
|
59,950
|
|
|
56,992
|
|
|
43,682
|
|
|||
Production taxes
|
31,410
|
|
|
18,443
|
|
|
27,194
|
|
|||
Transportation, gathering and processing expenses
|
18,415
|
|
|
10,151
|
|
|
8,128
|
|
|||
Exploration expense
|
4,669
|
|
|
1,102
|
|
|
948
|
|
|||
Impairment of properties and equipment
|
9,973
|
|
|
161,620
|
|
|
167,280
|
|
|||
Depreciation, depletion, and amortization
|
413,105
|
|
|
298,760
|
|
|
201,656
|
|
|||
Accretion of asset retirement obligations
|
7,080
|
|
|
6,293
|
|
|
3,455
|
|
|||
Loss on sale of properties and equipment
|
(43
|
)
|
|
(385
|
)
|
|
(75,972
|
)
|
|||
|
544,559
|
|
|
552,976
|
|
|
376,371
|
|
|||
Results of operations for crude oil and natural gas producing
activities before provision for income taxes |
(172,887
|
)
|
|
28,920
|
|
|
428,410
|
|
|||
|
|
|
|
|
|
||||||
Provision for income taxes
|
64,733
|
|
|
(10,394
|
)
|
|
(166,930
|
)
|
|||
|
|
|
|
|
|
||||||
Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs
|
$
|
(108,154
|
)
|
|
$
|
18,526
|
|
|
$
|
261,480
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Acquisition of properties: (1)
|
|
|
|
|
|
||||||
Proved properties (2)
|
$
|
268,567
|
|
|
$
|
3,561
|
|
|
$
|
11,973
|
|
Unproved properties
|
1,843,985
|
|
|
15
|
|
|
45,999
|
|
|||
Development costs (3)
|
383,336
|
|
|
552,104
|
|
|
608,176
|
|
|||
Exploration costs: (4)
|
|
|
|
|
|
||||||
Exploratory drilling
|
—
|
|
|
—
|
|
|
—
|
|
|||
Geological and geophysical
|
4,669
|
|
|
—
|
|
|
1
|
|
|||
Total costs incurred
|
$
|
2,500,557
|
|
|
$
|
555,680
|
|
|
$
|
666,149
|
|
|
|
|
|
|
|
(1)
|
Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property.
|
(2)
|
Includes approximately $40.9 million of infrastructure and pipeline costs in 2016.
|
(3)
|
Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells, and provide facilities to extract, treat, gather, and store crude oil, natural gas, and NGLs. Of these costs incurred for the years ended
December 31, 2016
,
2015
, and
2014
,
$204.6 million
,
$207.8 million
, and
$125.2 million
, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end.
|
(4)
|
Exploration costs - represents costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas, and NGLs.
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
|
|
|
|
||||
Proved crude oil and natural gas properties
|
$
|
3,499,718
|
|
|
$
|
2,881,189
|
|
Unproved crude oil and natural gas properties
|
1,874,671
|
|
|
60,498
|
|
||
Uncompleted wells, equipment and facilities
|
150,424
|
|
|
109,385
|
|
||
Capitalized costs
|
5,524,813
|
|
|
3,051,072
|
|
||
Less accumulated DD&A
|
(1,534,678
|
)
|
|
(1,131,705
|
)
|
||
Capitalized costs, net
|
$
|
3,990,135
|
|
|
$
|
1,919,367
|
|
|
|
|
|
|
As of December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
||||||
Future estimated cash flows
|
$
|
7,122,525
|
|
|
$
|
6,297,298
|
|
|
$
|
12,550,515
|
|
Future estimated production costs*
|
(1,624,167
|
)
|
|
(1,493,040
|
)
|
|
(2,746,811
|
)
|
|||
Future estimated development costs
|
(2,219,914
|
)
|
|
(2,036,685
|
)
|
|
(2,528,755
|
)
|
|||
Future estimated income tax expense
|
(597,476
|
)
|
|
(508,332
|
)
|
|
(2,336,510
|
)
|
|||
Future net cash flows
|
2,680,968
|
|
|
2,259,241
|
|
|
4,938,439
|
|
|||
10% annual discount for estimated timing of cash flows
|
(1,260,339
|
)
|
|
(1,162,377
|
)
|
|
(2,631,974
|
)
|
|||
Standardized measure of discounted future estimated net cash flows
|
$
|
1,420,629
|
|
|
$
|
1,096,864
|
|
|
$
|
2,306,465
|
|
|
|
|
|
|
|
*
|
Represents future estimated lease operating expenses, production taxes, transportation, gathering and processing expenses.
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
||||||
Beginning of period
|
$
|
1,096,864
|
|
|
$
|
2,306,465
|
|
|
$
|
1,782,163
|
|
Sales of crude oil, natural gas and NGLs production, net of production costs
|
(387,576
|
)
|
|
(293,127
|
)
|
|
(387,789
|
)
|
|||
Net changes in prices and production costs (1)
|
(205,760
|
)
|
|
(1,752,921
|
)
|
|
129,213
|
|
|||
Extensions, discoveries, and improved recovery, less related costs
|
15,128
|
|
|
489,178
|
|
|
1,444,581
|
|
|||
Sales of reserves
|
(3,745
|
)
|
|
(463
|
)
|
|
(402,595
|
)
|
|||
Purchases of reserves
|
487,636
|
|
|
374
|
|
|
238
|
|
|||
Development costs incurred during the period
|
268,672
|
|
|
368,840
|
|
|
161,404
|
|
|||
Revisions of previous quantity estimates
|
(320,286
|
)
|
|
(1,286,462
|
)
|
|
(654,318
|
)
|
|||
Changes in estimated income taxes
|
(13,630
|
)
|
|
902,994
|
|
|
(221,874
|
)
|
|||
Net changes in future development costs
|
391,145
|
|
|
112,958
|
|
|
46,499
|
|
|||
Accretion of discount
|
133,747
|
|
|
345,007
|
|
|
270,389
|
|
|||
Timing and other
|
(41,566
|
)
|
|
(95,979
|
)
|
|
138,554
|
|
|||
End of period
|
$
|
1,420,629
|
|
|
$
|
1,096,864
|
|
|
$
|
2,306,465
|
|
|
|
|
|
|
|
(1)
|
Our weighted-average price, net of production costs per Boe, in our 2016 reserve report decreased to
$15.73
as compared to
$17.30
for 2015 and
$37.78
for 2014.
|
|
2016
|
||||||||||||||
|
Quarter Ended
|
||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
||||||||
|
(in thousands, except per share data)
|
||||||||||||||
Total revenues
|
$
|
90,831
|
|
|
$
|
20,097
|
|
|
$
|
163,890
|
|
|
$
|
108,097
|
|
Total cost, expenses and other
|
193,864
|
|
|
163,379
|
|
|
179,178
|
|
|
178,608
|
|
||||
Loss from operations
|
(103,033
|
)
|
|
(143,282
|
)
|
|
(15,288
|
)
|
|
(70,511
|
)
|
||||
Loss before income taxes
|
(113,369
|
)
|
|
(153,777
|
)
|
|
(35,341
|
)
|
|
(90,636
|
)
|
||||
Net loss
|
$
|
(71,530
|
)
|
|
$
|
(95,450
|
)
|
|
$
|
(23,309
|
)
|
|
$
|
(55,639
|
)
|
|
|
|
|
|
|
|
|
||||||||
Earnings per share:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
(1.72
|
)
|
|
$
|
(2.04
|
)
|
|
$
|
(0.48
|
)
|
|
$
|
(0.94
|
)
|
Diluted
|
(1.72
|
)
|
|
(2.04
|
)
|
|
(0.48
|
)
|
|
(0.94
|
)
|
|
2015
|
||||||||||||||
|
Quarter Ended
|
||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
||||||||
|
(in thousands, except per share data)
|
||||||||||||||
Total revenues
|
$
|
144,632
|
|
|
$
|
50,960
|
|
|
$
|
231,100
|
|
|
$
|
168,634
|
|
Total costs, expenses and other
|
106,235
|
|
|
117,514
|
|
|
283,047
|
|
|
152,354
|
|
||||
Income (loss) from operations
|
38,397
|
|
|
(66,554
|
)
|
|
(51,947
|
)
|
|
16,280
|
|
||||
Income (loss) before income taxes
|
27,785
|
|
|
(76,986
|
)
|
|
(62,661
|
)
|
|
5,274
|
|
||||
Net income (loss)
|
$
|
17,062
|
|
|
$
|
(46,870
|
)
|
|
$
|
(41,494
|
)
|
|
$
|
3,022
|
|
|
|
|
|
|
|
|
|
||||||||
Earnings per share:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
0.47
|
|
|
$
|
(1.17
|
)
|
|
$
|
(1.04
|
)
|
|
$
|
0.08
|
|
Diluted
|
0.46
|
|
|
(1.17
|
)
|
|
(1.04
|
)
|
|
0.07
|
|
Description
|
|
Beginning
Balance January 1 |
|
Charged to
Costs and Expenses |
|
Deductions (1)
|
|
Ending
Balance December 31 |
||||||||
|
|
(in thousands)
|
||||||||||||||
|
|
|
|
|
|
|
|
|
||||||||
2016:
|
|
|
|
|
|
|
|
|
||||||||
Allowance for uncollectible notes
|
|
$
|
—
|
|
|
$
|
44,038
|
|
|
$
|
—
|
|
|
$
|
44,038
|
|
Allowance for doubtful accounts
|
|
2,009
|
|
|
1,309
|
|
|
1,128
|
|
|
2,190
|
|
||||
Allowance for expirations of unproved crude oil and natural gas properties
|
|
144
|
|
|
215
|
|
|
—
|
|
|
359
|
|
||||
2015:
|
|
|
|
|
|
|
|
|
||||||||
Allowance for doubtful accounts
|
|
486
|
|
|
1,700
|
|
|
177
|
|
|
2,009
|
|
||||
Allowance for expirations of unproved crude oil and natural gas properties
|
|
9,293
|
|
|
7,012
|
|
|
16,161
|
|
|
144
|
|
||||
2014:
|
|
|
|
|
|
|
|
|
||||||||
Allowance for doubtful accounts
|
|
896
|
|
|
78
|
|
|
488
|
|
|
486
|
|
||||
Allowance for expirations of unproved crude oil and natural gas properties
|
|
5,142
|
|
|
4,465
|
|
|
314
|
|
|
9,293
|
|
(1)
|
For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for expirations of unproved crude oil and natural gas properties, deductions represent accumulated amortization of expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset.
|
(a)
|
(1)
|
Exhibits:
|
|
|
See Exhibits Index on the following page.
|
|
|
|
|
Incorporated by Reference
|
|
|
||||||
Exhibit Number
|
|
Exhibit Description
|
|
Form
|
|
SEC File Number
|
|
Exhibit
|
|
Filing Date
|
|
Filed Herewith
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.1
|
|
Plan of Conversion, dated June 5, 2015, by PDC Energy, Inc. (the "Company").
|
|
8-K12B
|
|
001-37419
|
|
2.1
|
|
6/8/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.2
|
|
Stock Purchase and Sale Agreement, dated August 23, 2016, by and among the seller parties thereto, Kimmeridge Energy Management Company GP, LLC, Arris Petroleum Corporation, and PDC Energy, Inc.
|
|
8-K
|
|
001-37419
|
|
2.1
|
|
8/24/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.3
|
|
Asset Purchase and Sale Agreement, dated August 23, 2016, by and among 299 Resources, LLC, 299 Production, LLC, 299 Pipeline, LLC, Kimmeridge Energy Management Company GP, LLC and PDC Energy, Inc.
|
|
8-K
|
|
001-37419
|
|
2.2
|
|
8/24/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.1
|
|
Certificate of Incorporation of the Company.
|
|
8-K12B
|
|
001-37419
|
|
3.1
|
|
6/8/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.2
|
|
By-laws of the Company.
|
|
8-K12B
|
|
001-37419
|
|
3.2
|
|
6/8/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.1
|
|
Form of Common Stock Certificate of the Company.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.2
|
|
Indenture, dated as of October 3, 2012, by and between the Company and U.S. Bank Trust National Association, as Trustee, including the form of 7.75% Senior Notes due 2022.
|
|
8-K
|
|
000-07246
|
|
4.1
|
|
10/3/2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.3
|
|
Base Indenture, dated as of September 14, 2016, by and between the Company and U.S. Bank Trust National Association, as Trustee.
|
|
8-K
|
|
001-37419
|
|
4.1
|
|
9/14/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.4
|
|
First Supplemental Indenture, dated as of September 14, 2016, by and between the Company and U.S. Bank Trust National Association, as Trustee, relating to the 1.125% Convertible Senior Notes due 2021.
|
|
8-K
|
|
001-37419
|
|
4.2
|
|
9/14/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.5
|
|
Indenture, dated as of September 15, 2016, by and between PDC Energy, Inc. and U.S. Bank Trust National Association, as Trustee, relating to the 6.125% Senior Notes due 2024.
|
|
8-K
|
|
001-37419
|
|
4.1
|
|
9/15/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.1*
|
|
Form of Indemnification Agreement.
|
|
8-K
|
|
000-07246
|
|
10.1
|
|
6/8/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.2*
|
|
401(k) and Profit Sharing Plan, as amended on January 4, 2016.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.3*
|
|
Amended and Restated Non-Employee Director Deferred Compensation Plan.
|
|
10-K
|
|
000-07246
|
|
10.3
|
|
2/21/2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.4*
|
|
2004 Long-Term Equity Compensation Plan amended and restated as of March 8, 2008 ("2004 Plan").
|
|
10-K
|
|
000-07246
|
|
10.26
|
|
2/27/2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.4.1*
|
|
Summary of 2010 Stock Appreciation Rights and Restricted Stock Awards under the 2004 Plan.
|
|
8-K
|
|
000-07246
|
|
|
|
4/23/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.5*
|
|
Amended and Restated 2010 Long-Term Equity Compensation Plan, as amended.
|
|
10-K
|
|
001-37419
|
|
10.5
|
|
2/22/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.6*
|
|
Executive Severance Compensation Plan, as amended.
|
|
10-K
|
|
001-37419
|
|
10.6
|
|
2/22/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7*
|
|
Form of 2011 Restricted Stock/Stock Appreciation Rights Agreement.
|
|
10-K
|
|
000-07246
|
|
10.5.2
|
|
2/21/2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.1*
|
|
Form of 2013 Performance Share Agreement.
|
|
10-K
|
|
000-07246
|
|
10.9
|
|
2/27/2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.2*
|
|
Form of 2013 Restricted Stock/Stock Appreciation Rights Agreement.
|
|
10-K
|
|
000-07246
|
|
10.10
|
|
2/27/2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.3*
|
|
Form of 2014 Performance Share Agreement.
|
|
10-K
|
|
000-07246
|
|
10.5.4
|
|
2/19/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incorporated by Reference
|
|
|
||||||
Exhibit Number
|
|
Exhibit Description
|
|
Form
|
|
SEC File Number
|
|
Exhibit
|
|
Filing Date
|
|
Filed Herewith
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.4*
|
|
Form of 2014 Restricted Stock/Stock Appreciation Rights Agreement.
|
|
10-K
|
|
000-07246
|
|
10.5.5
|
|
2/19/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.5*
|
|
Form of 2015 Performance Share Agreement.
|
|
10-K
|
|
000-07246
|
|
10.5.6
|
|
2/19/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.6*
|
|
Form of 2015 Restricted Stock Unit Agreement.
|
|
10-K
|
|
000-07246
|
|
10.5.7
|
|
2/19/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.7*
|
|
Form of 2015 Stock Appreciation Rights Agreement.
|
|
10-K
|
|
000-07246
|
|
10.5.8
|
|
2/19/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.8*
|
|
Form of 2016 Performance Share Agreement.
|
|
10-K
|
|
001-37419
|
|
10.7.8
|
|
2/22/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.8*
|
|
Employment Agreement with Gysle R. Shellum, Chief Financial Officer, dated as of April 19, 2010.
|
|
8-K
|
|
000-07246
|
|
10.2
|
|
4/23/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.9*
|
|
Employment Agreement with Daniel W. Amidon, General Counsel and Corporate Secretary, dated as of April 19, 2010.
|
|
8-K
|
|
000-07246
|
|
10.3
|
|
4/23/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.10*
|
|
Employment Agreement with Lance A. Lauck, Senior Vice President of Business Development, dated as of April 19, 2010.
|
|
8-K
|
|
000-07246
|
|
10.4
|
|
4/23/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.11
|
|
Third Amended and Restated Credit Agreement dated as of May 21, 2013, among PDC Energy, Inc. as Borrower, Riley Natural Gas Company, a Subsidiary of PDC Energy, Inc., as Guarantor, JP Morgan Chase Bank, N.A. as Administrative Agent, J.P. Morgan Securities LLC as Sole Bookrunner and Co-Lead Arranger, Wells Fargo Bank, N.A. as Syndication Agent, and Wells Fargo Securities, LLC as Co-Lead Arranger, and Certain Lenders.
|
|
8-K
|
|
000-07246
|
|
10.1
|
|
5/28/2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.11.1
|
|
First and Second Amendments to Third Amended and Restated Credit Agreement dated as of May 14, 2014 and September 30, 2015, respectively, among PDC Energy, Inc. as the Borrower, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders.
|
|
10-K
|
|
001-37419
|
|
10.11.1
|
|
2/22/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.11.2
|
|
Third Amendment to the Third Amended and Restated Credit Agreement, dated as of September 6, 2016, among the Company, as Borrower, certain Subsidiaries of the Company, as Guarantors, the lenders from time to time party thereto (the “Lenders”) and JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders.
|
|
8-K
|
|
001-37419
|
|
10.1
|
|
9/8/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.11.3
|
|
Fourth Amendment to the Third Amended and Restated Credit Agreement, dated as of October 14, 2016, among the Company, as Borrower, certain Subsidiaries of the Company, as Guarantors, the lenders from time to time party thereto (the “Lenders”) and JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders.
|
|
10-Q
|
|
001-37419
|
|
99.1
|
|
11/3/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.12*
|
|
Consulting Agreement with James M. Trimble, dated as of June 18, 2014.
|
|
10-Q
|
|
000-07246
|
|
10.1
|
|
8/8/2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.13*
|
|
Retirement Agreement with Gysle R. Shellum, Chief Financial Officer, dated October 26, 2015.
|
|
8-K
|
|
001-37419
|
|
10.1
|
|
10/27/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.14*
|
|
Change of Control and Severance Plan.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.14.1*
|
|
Amendment to the PDC Energy Change of Control and Severance Plan
|
|
|
|
|
|
10.14.1
|
|
2/28/2017
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.15
|
|
Registration Rights Agreement, dated as of September 15, 2016, by and between PDC Energy, Inc. and J.P. Morgan Securities LLC, as representative of the initial purchasers, relating to the 6.125% Senior Notes due 2024.
|
|
8-K
|
|
001-37419
|
|
10.2
|
|
9/5/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.16
|
|
Investment Agreement, dated December 6, 2016, by and among the Investor parties identified therein and PDC Energy, Inc. (relating to the Stock Purchase and Sale Agreement).
|
|
8-K
|
|
001-37419
|
|
10.1
|
|
12/7/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.17
|
|
Investment Agreement, dated December 6, 2016, by and among the Investor parties identified therein and PDC Energy, Inc. (relating to the Asset Purchase and Sale Agreement).
|
|
8-K
|
|
001-37419
|
|
10.2
|
|
12/7/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12.1
|
|
Computation of Ratio of Earnings to Fixed Charges.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21.1
|
|
Subsidiaries.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23.1
|
|
Consent of PricewaterhouseCoopers LLP.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23.2
|
|
Consent of Ryder Scott Company, L.P., Petroleum Consultants.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PDC ENERGY, INC.
|
|
|
|
By: /s/ Barton R. Brookman
|
|
Barton R. Brookman
|
|
President and Chief Executive Officer
|
|
|
|
February 28, 2017
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ Barton R. Brookman
|
|
President, Chief Executive Officer and Director
|
|
February 28, 2017
|
Barton R. Brookman
|
|
(principal executive officer)
|
|
|
|
|
|
|
|
/s/ David W. Honeyfield
|
|
Senior Vice President and Chief Financial Officer
|
|
February 28, 2017
|
David W. Honeyfield
|
|
(principal financial officer)
|
|
|
|
|
|
|
|
/s/ R. Scott Meyers
|
|
Chief Accounting Officer
|
|
February 28, 2017
|
R. Scott Meyers
|
|
(principal accounting officer)
|
|
|
|
|
|
|
|
/s/ Jeffrey C. Swoveland
|
|
Chairman and Director
|
|
February 28, 2017
|
Jeffrey C. Swoveland
|
|
|
|
|
|
|
|
|
|
/s/ Joseph E. Casabona
|
|
Director
|
|
February 28, 2017
|
Joseph E. Casabona
|
|
|
|
|
|
|
|
|
|
/s/ Anthony J. Crisafio
|
|
Director
|
|
February 28, 2017
|
Anthony J. Crisafio
|
|
|
|
|
|
|
|
|
|
/s/ Larry F. Mazza
|
|
Director
|
|
February 28, 2017
|
Larry F. Mazza
|
|
|
|
|
|
|
|
|
|
/s/ David C. Parke
|
|
Director
|
|
February 28, 2017
|
David C. Parke
|
|
|
|
|
|
|
|
|
|
/s/ Kimberly Luff Wakim
|
|
Director
|
|
February 28, 2017
|
Kimberly Luff Wakim
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal Tax
Identification Number
|
Participating Employer Name
|
Designation
|
27-1195623
|
PDC Mountaineer LLC
|
Unrelated
|
Contribution type
|
Age Requirement
|
Service Requirement
|
Entry Date
|
All Sources
|
18.00
|
1.00 month(s)
|
First day of each month
|
Source
|
Exclusion (s)
|
Employee Deferral Contributions and
Qualified Nonelective Contributions
|
Differential Wages, Stock award compensation, Reimbursements or Other Expense Allowances, Fringe Benefits (cash and non-cash), Moving Expenses, Deferred Compensation, Welfare Benefits
|
Employer Matching Contributions
|
Differential Wages, Stock award compensation, Reimbursements or Other Expense Allowances, Fringe Benefits (cash and non-cash), Moving Expenses, Deferred Compensation, Welfare Benefits
|
Employer Nonelective Contributions
|
Differential Wages, Stock award compensation, Reimbursements or Other Expense Allowances, Fringe Benefits (cash and non-cash), Moving Expenses, Deferred Compensation, Welfare Benefits
|
Applicable Year(s)
|
Method
|
Measurement Period
|
Plan Year(s) before 2006
|
General
|
Jan 1 to Dec 31
|
2006
|
General or Elapsed Time*
|
Jan 1 to Dec 31
|
Plan Year(s) after 2006
|
Elapsed Time
|
Jan 1 to Dec 31
|
Source
|
Amount
|
Vested Percentage
|
Vested Amount
|
Employee
|
$2,000
|
100%†
|
$2,000
|
Employer
|
$1,000
|
80%
|
800
|
Total
|
$3,000
|
|
$2,800
|
•
|
You are re-employed by your Employer before you incur five consecutive one-year breaks in service, and
|
•
|
If you received distribution of your vested Account and you repay the full amount of the distribution before the end of the five-year period that begins on the date you are re-employed.
|
•
|
Examine, without charge, at the Plan Administrator’s office and at other specified locations, such as worksites and union halls, all documents governing the Plan, including insurance contracts and collective bargaining agreements, and a copy of the latest annual report (Form 5500 Series) filed by the Plan with the U.S. Department of Labor and available at the Public Disclosure Room of the Employee Benefits Security Administration.
|
•
|
Obtain, upon written request to the Plan Administrator, copies of documents governing the operation of the plan, including insurance contracts and collective bargaining agreements, and copies of the latest annual report (Form 5500 Series) and updated Summary Plan Description. The Plan Administrator may make a reasonable charge for the copies.
|
•
|
Receive a summary of the Plan’s annual financial report. The Plan Administrator is required by law to furnish each Participant with a copy of this Summary Annual Report each year.
|
•
|
Obtain a statement telling you the fair market value of your vested, accrued benefit, as of the date for which the benefits are reported, if you stop working under the Plan now. If you do not have a right to a benefit under the plan, the statement will tell you how many more years you have to work to get a right to a benefit. This statement must be requested in writing and is not required to be given more than once every twelve (12) months. The Plan must provide the statement free of charge.
|
•
|
If the Company is ranked at or above the 90
th
percentile of the Peer Companies, 200% of the Target Award
|
•
|
If the Company is ranked at the 50
th
percentile or median of the Peer Companies, including the Company, 100% of the Target Award
|
•
|
If the Company is ranked at the 25
th
percentile of the Peer Companies, including the Company, 50% of the Target Award
|
•
|
If the Company is ranked below the 25
th
percentile of the Peer Companies, including the Company, no award will be paid
|
•
|
Bill Barrett Corporation (BBG)
|
•
|
Bonanza Creek Energy, Inc. (BCEI)
|
•
|
Callon Petroleum Company (CPE)
|
•
|
Carrizo Oil & Gas Inc. (CRZO)
|
•
|
Energen Corp. (EGN)
|
•
|
Gulfport Energy Corp. (GPOR)
|
•
|
Laredo Petroleum Holdings, Inc. (LPI)
|
•
|
Matador Resources Company (MTDR)
|
•
|
Oasis Petroleum Inc. (OAS)
|
•
|
Parsley Energy, Inc. (PE)
|
•
|
SM Energy Company (SM)
|
•
|
Synergy Resources Corporation (SYRG)
|
•
|
WPX Energy, Inc. (WPX)
|
I.
|
DEFINITIONS AND CONSTRUCTION
|
II.
|
CHANGE OF CONTROL AND SEVERANCE BENEFITS
|
III.
|
ADMINISTRATION OF PLAN
|
IV.
|
GENERAL PROVISIONS
|
1.
|
Termination of Employment
. Executive’s employment with the Company shall terminate on _____________, 20__ (the “Termination Date”).
|
2.
|
Severance Benefits
. Pursuant to the terms of the Plan, and in consideration of Executive’s release of claims and the other covenants and agreements contained herein and therein, and provided that Executive has signed this Release and delivered it to the Company and has not exercised any revocation rights as provided in Section 6 below, the Company shall provide the severance benefits described in Article II of the Plan (the “Benefits”) in the time and manner provided therein; provided, however, that the Company’s obligations will be excused if Executive breaches any of the provisions of the Release including, without limitation, Sections 7, 8 and 10 hereof. Executive acknowledges and agrees that the Benefits constitute consideration beyond that which, but for the mutual covenants set forth in this Release and the
|
3.
|
Release Effective Date
. Provided that it has not been revoked pursuant to Section 6 hereof, this Release will become effective on the eighth (8th) day after the date of its execution by Executive (the “Release Effective Date”).
|
4.
|
Effect of Revocation
. Executive acknowledges and agrees that if Executive revokes this Release pursuant to Section 6 hereof, Executive will have no right to receive the Benefits.
|
5.
|
General Release
. In consideration of the Company’s obligations, Executive hereby releases, acquits and forever discharges Company and each of its subsidiaries and affiliates and each of their respective officers, employees. directors, successors and assigns from any and all claims, actions or causes of action in any way related to Executive’s employment with the Company or the termination thereof, whether arising from tort, statute or contract, including but not limited to, claims of defamation, claims arising under the Employee Retirement Income Security Act of 1974, as amended, the Age Discrimination in Employment Act of 1967, as amended by the Older Workers Benefit Protection Act of 1990, Title VII of the Civil Rights Act of 1964, as amended, the Americans with Disabilities Act, the Family and Medical Leave Act, the discrimination and wage payment laws of Colorado and West Virginia and any other federal, state or local statutes or ordinances of the United States, it being Executive’s intention and the intention of the Company to make this release as broad and as general as the law permits. Executive understands that this Agreement does not waive any rights or claims that may arise after Executive’s execution of it and does not apply to claims arising under the terms of this Agreement.
|
6.
|
Review and Revocation Period
. Executive acknowledges that the Company has advised Executive that Executive may consult with an attorney of Executive’s own choosing (and at Executive’s expense) prior to signing this Release and that Executive has been given at least twenty-one (21) days during which to consider the provisions of this Release, although Executive may sign and return it sooner. Executive further acknowledges that Executive has been advised by the Company that after executing this Release and delivering it to the Company, Executive will have seven (7) days to revoke this Release, and that this Release shall not become effective or enforceable until such seven (7) day revocation period has expired. Executive acknowledges and agrees that if Employee wishes to revoke this Release, Executive must do so in writing, and that such revocation must be signed by Executive and received by the Chairman of the Board of the Company (or the Chair of the Compensation Committee) no later than 5:00 p.m. Mountain Time on the seventh (7th) day after Executive has executed and delivered this Release. Executive acknowledges and agrees that, in the event that Executive revokes this Release, Executive will have no right to receive any benefits hereunder, including the Benefits. Executive represents that Executive has read this Release and understands its terms and enters into this Release freely, voluntarily and without coercion.
|
7.
|
Non-Solicitation
. The Executive shall not, directly or indirectly, for a period of two (2) years after the Termination Date (i) solicit, directly or indirectly, the services of any person who was a full-time employee of the Company, its subsidiaries, divisions, or affiliates, or otherwise induce such employee to terminate or reduce employment with the Company, or (ii) solicit the business of any person who was a client or customer of the Company, its subsidiaries, divisions, or affiliates, in each case at any time during the last year of the Term. For purposes of this Agreement, the term “person” includes natural persons, corporations, business trusts, associations, sole proprietorships, unincorporated organizations, partnerships, joint ventures, limited liability companies or partnerships, and governments, or any agencies, instrumentalities, or political subdivisions thereof.
|
8.
|
Cooperation in Litigation
. At the Company’s reasonable request, Executive shall use his good faith efforts to cooperate with the Company, its Affiliates, and each of its and their respective attorneys or other legal representatives (“Attorneys”) in connection with any claim, litigation or judicial or arbitral proceeding which is material to the Company and is now pending or may hereinafter be brought against the Released Parties by any third party; provided, that, Executive’s cooperation is essential, in the opinion of the Company, to the Company’s case. Executive’s duty of cooperation will include, but not be limited to (a) meeting with the Company’s and/or its Affiliates’ Attorneys by telephone or in person at mutually convenient times and places in order to state truthfully Executive’s knowledge of matters at issue and recollection of events; (b) appearing at the Company’s, its Affiliates’ and/or their Attorneys’ request (and, to the extent possible, at a time convenient to Executive that does not conflict with the needs or requirements of Executive’s then-current employer) as a witness at depositions or trials, without necessity of a subpoena, in order to state truthfully Executive’s knowledge of matters at issue; and (c) signing at the Company’s, its Affiliates’ and/or their Attorneys’ request declarations or affidavits that truthfully state matters of which Executive has knowledge. The Company shall reimburse Executive for the reasonable expenses incurred by him or her in the course of his or her cooperation hereunder and shall pay to Executive per diem compensation in an amount equal to the daily prorated portion of the Executive’s base salary immediately prior to the Termination Date. The obligations set forth in this Section 8 shall survive any termination or revocation of this Release.
|
9.
|
Non-Admission of Liability
. Nothing in this Release will be construed as an admission of liability by Executive or the Released Parties; rather, Executive and the Released Patties arc resolving all matters arising out of the employeremployee relationship between Executive and the Company and all other relationships between Executive and the Released Patties.
|
10.
|
Nondisparagement
. Executive agrees not to make negative comments or otherwise disparage the Company or its officers, directors, employees, shareholders or agents, in any manner likely to be harmful to them or their business, business reputation or personal reputation. The Company agrees that the members of the Board of Directors and officers of the Company as of the date hereof will not, while employed by the Company or serving as a director of the Company, as the case may be, make negative comments about the Executive or otherwise disparage the Executive in any manner that is likely to be harmful to the Executive’s business or personal reputation. The foregoing shall not be violated by truthful statements in response to legal process or required governmental testimony or filings, and the foregoing limitation on the
|
11.
|
Binding Effect
. This Release will be binding upon the Parties and their respective heirs, administrators, representatives, executors, successors and assigns, and will inure to the benefit of the Parties and their respective heirs, administrators, representatives, executors, successors and assigns.
|
12.
|
Governing Law
. This Release will be governed by and construed and enforced in accordance with the laws of the State of Colorado applicable to agreements negotiated, entered into and wholly to be performed therein.
|
13.
|
Severability
. Each of the respective rights and obligations of the Parties hereunder will be deemed independent and may be enforced independently irrespective of any of the other rights and obligations set forth herein. If any provision of this Release should be held illegal or invalid, such illegality or in validity will not affect in any way other provisions hereof, all of which will continue, nevertheless, in full force and effect.
|
14.
|
Counterparts
. This Release may be signed in counterparts and each counterpart will be deemed to be an original but together all such counterparts will be deemed a single agreement.
|
15.
|
Entire Agreement; Modification
. This Release constitutes the entire understanding between the Parties with respect to the subject matter hereof and may not be modified without the express written consent of both Parties. This Release supersedes all prior written and/or oral and all contemporaneous oral agreements, understandings and negotiations regarding its subject matter. This Release may not be modified or canceled in any manner except by a writing signed by both Parties.
|
16.
|
Acceptance
. Executive may confirm his acceptance of the terms and conditions of this Release by signing and returning two (2) original copies of this Release to the Chairman of the Board of the Company, no later than 5:00 p.m. Mountain Time twenty-one (21) days after Executive’s receipt of notice of termination.
|
PDC ENERGY, INC.
|
||||||||||||||||||||
Statement of Computation of Ratio of Earnings to Fixed Charges
|
||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
|
|
Year Ended December 31,
|
|
|||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
|||||||||
|
|
(dollars in thousands)
|
|
|||||||||||||||||
Earnings:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Income (loss) from continuing operations before income taxes
|
|
$
|
(393,123
|
)
|
|
$
|
(106,588
|
)
|
|
$
|
177,228
|
|
|
(32,963
|
)
|
|
$
|
(30,688
|
)
|
|
Fixed charges (see below)
|
|
69,840
|
|
|
55,844
|
|
|
53,512
|
|
|
54,002
|
|
|
50,228
|
|
|
||||
Amortization of capitalized interest
|
|
3,463
|
|
|
2,486
|
|
|
1,379
|
|
|
1,096
|
|
|
871
|
|
|
||||
Interest capitalized
|
|
(4,489
|
)
|
|
(5,060
|
)
|
|
(3,468
|
)
|
|
(1,709
|
)
|
|
(896
|
)
|
|
||||
Total adjusted earnings (loss) available for fixed charges
|
|
$
|
(324,309
|
)
|
|
$
|
(53,318
|
)
|
|
$
|
228,651
|
|
|
20,426
|
|
|
$
|
19,515
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Fixed Charges:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Interest and debt expense (a)
|
|
$
|
61,972
|
|
|
$
|
47,571
|
|
|
$
|
47,842
|
|
|
50,143
|
|
|
$
|
47,505
|
|
|
Interest capitalized
|
|
4,489
|
|
|
5,060
|
|
|
3,468
|
|
|
1,709
|
|
|
896
|
|
|
||||
Interest component of rental expense (b)
|
|
3,379
|
|
|
3,213
|
|
|
2,202
|
|
|
2,150
|
|
|
1,827
|
|
|
||||
Total fixed charges
|
|
$
|
69,840
|
|
|
$
|
55,844
|
|
|
$
|
53,512
|
|
|
54,002
|
|
|
$
|
50,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Ratio of Earnings to Fixed Charges
|
|
—
|
|
(c)
|
—
|
|
(c)
|
4.3
|
x
|
|
—
|
|
(c)
|
—
|
|
(c)
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Represents interest expense on long-term debt and amortization of debt discount and issuance costs.
|
(b)
|
Represents the portion of rental expense which we believe represents an interest component.
|
(c)
|
For the years ended December 31, 2016, 2015, 2013, and 2012, earnings were insufficient to cover total fixed charges by
$394.1 million
,
$109.2 million
,
$33.6 million
,
and
$30.7 million
, respectively.
|
|
/s/ Ryder Scott Company, L.P.
|
|
|
|
RYDER SCOTT COMPANY, L.P.
|
|
TBPE Firm Registration No. F-1580
|
|
|
Denver, CO
|
|
February 28, 2017
|
|
|
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
||
|
|
|
By:
|
|
s/ J. Carter Henson, Jr.
|
|
|
J. Carter Henson, Jr., P.E.
|
|
|
Senior Vice President
|
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
|
1.
|
I have reviewed this Annual Report on Form 10-K of PDC Energy, Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c.
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date:
|
February 28, 2017
|
|
/s/ Barton R. Brookman
|
|
Barton R. Brookman
|
|
President and Chief Executive Officer
|
1.
|
I have reviewed this Annual Report on Form 10-K of PDC Energy, Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c.
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date:
|
February 28, 2017
|
|
/s/ David W. Honeyfield
|
|
David W. Honeyfield
|
|
Senior Vice President and Chief Financial Officer (Principal Financial Officer)
|
1.
|
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
2.
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
/s/ Barton R. Brookman
|
|
February 28, 2017
|
Barton R. Brookman
|
|
|
President and Chief Executive Officer
|
|
|
|
|
|
|
|
|
/s/ David W. Honeyfield
|
|
February 28, 2017
|
David W. Honeyfield
|
|
|
Senior Vice President and Chief Financial Officer (Principal Financial Officer)
|
|
|
As of December 31, 2016
|
||||||||||||||||
|
|
Proved
|
||||||||||||||
|
|
Developed
|
|
|
|
Total
|
||||||||||
|
|
Producing
|
|
Non-Producing
|
|
Undeveloped
|
|
Proved
|
||||||||
Net Remaining Reserves
|
|
|
|
|
|
|
|
|
||||||||
Oil/Condensate - MBBL
|
|
26,660.2
|
|
|
—
|
|
|
76,595.9
|
|
|
103,256.1
|
|
||||
Plant Products - MBBL
|
|
22,615.5
|
|
|
—
|
|
|
54,509.3
|
|
|
77,124.8
|
|
||||
Gas - MMCF
|
|
250,578
|
|
|
—
|
|
|
520,562
|
|
|
771,140
|
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Income Data (M$)
|
|
|
|
|
|
|
|
|
||||||||
Future Gross Revenue
|
|
$
|
1,696,877
|
|
|
$
|
—
|
|
|
$
|
4,509,114
|
|
|
6,205,991
|
|
|
Deductions
|
|
578,679
|
|
|
51,006
|
|
|
2,635,148
|
|
|
3,264,833
|
|
||||
Future Net Income (FNI)
|
|
$
|
1,118,198
|
|
|
$
|
(51,006
|
)
|
|
$
|
1,873,966
|
|
|
$
|
2,941,158
|
|
|
|
|
|
|
|
|
|
|
||||||||
Discounted FNI @ 10%
|
|
$
|
791,948
|
|
|
$
|
(10,011
|
)
|
|
$
|
740,456
|
|
|
$
|
1,522,393
|
|
|
|
Discounted Future Net Income - (M$)
|
||||
|
|
As of December 31, 2016
|
||||
Discount Rate Percent
|
|
|
Total Proved
|
|
||
|
|
|
|
|
||
5
|
|
|
$
|
2,067,053
|
|
|
15
|
|
|
$
|
1,163,468
|
|
|
20
|
|
|
$
|
915,931
|
|
|
25
|
|
|
$
|
738,712
|
|
|
Geographic
Area
|
Product
|
Price
Reference
|
Average Benchmark
Prices
|
Average Realized
Prices
|
North America
|
|
|
|
|
United States
|
Oil/Condensate
|
WTI Cushing
|
$42.75/Bbl
|
$38.57/Bbl
|
NGLs
|
WTI Cushing
|
$42.75/Bbl
|
$11.73/Bbl
|
|
Gas
|
Henry Hub
|
$2.48/MMBTU
|
$1.90/MCF
|
|
|
Net Reserves
|
|
Future Net Revenue (M$)
|
|||||||||||
Category
|
|
Oil (MMBL)
|
|
NGL (MMBL)
|
|
Gas (MMCF)
|
|
Total
|
|
Present Worth at 10%
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved Developed Producing
|
|
3,353.2
|
|
|
1,580.9
|
|
|
13,873.8
|
|
|
102,034.3
|
|
|
70,390.2
|
|
Proved Undeveloped
|
|
11,559.5
|
|
|
5,583.6
|
|
|
48,682.9
|
|
|
235,251.9
|
|
|
82,083.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total Proved
|
|
14,912.7
|
|
|
7,164.5
|
|
|
62,556.7
|
|
|
337,286.2
|
|
|
152,473.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Totals may not add because of rounding.
|
|
|
|
|
|
|
|
|
|
|