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10-Q: PDC ENERGY, INC.

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(EDGAR Online via COMTEX) -- ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our condensed consolidated financial statements and related notes included elsewhere in this report. Further, we encourage you to review the Special Note Regarding Forward-Looking Statements.

EXECUTIVE SUMMARY

Production and Financial Overview

Production volumes increased to 12.7 MMboe and 36.4 MMboe for the three and nine months ended September 30, 2019, respectively, representing increases of 26 percent and 28 percent as compared to the three and nine months ended September 30, 2018, respectively. Crude oil production increased 13 percent and 19 percent for the three and nine months ended September 30, 2019, respectively, compared to the three and nine months ended September 30, 2018, respectively. Natural gas production increased 35 percent in each of the three and nine months ended September 30, 2019 compared to the three and nine months ended September 30, 2018. NGLs production increased 37 percent and 35 percent for the three and nine months ended September 30, 2019, respectively, compared to the three and nine months ended September 30, 2018, respectively. For the month ended September 30, 2019, we maintained an average daily production rate of approximately 138,000 Boe per day, up from approximately 121,000 Boe per day for the month ended September 30, 2018.

On a sequential quarterly basis, total production for the three months ended September 30, 2019 as compared to the three months ended June 30, 2019 increased by two percent and crude oil production decreased by one percent. The increase in total production volumes was primarily related to the timing of wells turned-in-line in both areas of production, partially offset by elevated gathering system line pressures and unplanned facility downtime in the Wattenberg Field. The decrease in crude oil production was primarily related to elevated gathering system line pressures and unplanned facility downtime.

Crude oil, natural gas and NGLs sales revenue decreased to $307.4 million and $967.5 million for the three and nine months ended September 30, 2019, respectively, compared to $372.4 million and $1.0 billion for the three and nine months ended September 30, 2018, respectively. The 18 percent and four percent decreases in sales revenues were driven by the 34 percent and 25 percent decreases in weighted-average realized commodity prices, partially offset by the 26 percent and 28 percent increases in production, as compared to the prior periods.

We had positive net settlements from our commodity derivative contracts of $1.8 million for the three months ended September 30, 2019 and negative net settlements from our commodity derivative contracts of $19.8 million for the nine months ended September 30, 2019, as compared to negative net settlements of $48.1 million and $90.5 million for the three and nine months ended September 30, 2018.

The combined revenue from crude oil, natural gas and NGLs sales and net settlements from our commodity derivative instruments decreased five percent to $309.2 million for the three months ended September 30, 2019 from $324.3 million for the three months ended September 30, 2018 and increased four percent to $947.7 million for the nine months ended September 30, 2019 from $913.1 million for the nine months ended September 30, 2018.

For the three months ended September 30, 2019, we generated net income of $15.9 million and for the nine months ended September 30, 2019, we generated a net loss of $35.7 million, or $0.25 and $(0.55) per diluted share, respectively, compared to net losses of $3.4 million and $176.8 million, respectively, or $(0.05) and $(2.68) per diluted share, respectively, for the comparable periods in 2018. Our net income for the three months ended September 30, 2019 as compared to the net loss for the three months ended September 30, 2018 was primarily due to the gain in commodity price risk management for the three months ended September 30, 2019 as compared to the loss in the three months ended September 30, 2018, partially offset by the increase in the loss on sale of properties and equipment of $41.8 million for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018. Our net loss for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018 was most positively impacted by the decrease in the loss in commodity price risk management, the decrease in impairments of properties and equipment and the $34.0 million gain from the Midstream Asset Divestitures, which were partially offset by the $45.6 million loss from sale of properties and equipment resulting from an acreage acquisition.

During the three and nine months ended September 30, 2019, our adjusted EBITDAX, a non-U.S. GAAP financial measure, was $214.7 million and $646.4 million, respectively, compared to $215.3 million and $621.1 million, respectively, for the comparable periods of 2018. The decrease for the three months ended September 30, 2019 was primarily due to the

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decrease in crude oil, natural gas and NGLs sales of $65.0 million. The decrease was partially offset by the increase in commodity derivative settlements of $49.9 million and the decrease in operating costs of $12.9 million for the three months ended September 30, 2019. The increase for the nine months ended September 30, 2019 was primarily due to the decrease in the loss on commodity derivative settlements of $70.7 million, which was partially offset by the decrease in crude oil, natural gas and NGLs sales of $36.1 million and the increase in operating costs of $13.6 million. See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures.

Our cash flows from operations were $675.7 million and $577.8 million and our adjusted cash flows from operations, a non-U.S. GAAP financial measure, were $601.9 million and $575.3 million for the nine months ended September 30, 2019 and September 30, 2018, respectively.

Pending Acquisition

On August 25, 2019, we and SRC entered into the Merger Agreement relating to the SRC Acquisition. We expect the SRC Acquisition to be completed early in the first quarter of 2020, subject to PDC and SRC shareholder approval, respectively, and the satisfaction of certain other customary closing conditions. The value of the SRC Acquisition, which will include assumption of SRC's net debt, will be dependent upon the market value of our common stock on the date of closing. We estimate that we will issue up to approximately 40 million shares of our common stock in connection with the SRC Acquisition. See Item 1A. Risk Factors for risk factors related to the SRC Acquisition.

Liquidity

Available liquidity as of September 30, 2019 was $1.2 billion, which was comprised of $4.6 million of cash and cash equivalents and $1.2 billion available for borrowing under our revolving credit facility. In October 2019, as part of our semi-annual redetermination, the borrowing base on our revolving credit facility was reaffirmed at $1.6 billion and we elected to retain our commitment amount at $1.3 billion. Based on our current production forecast for 2019 and assuming a NYMEX crude oil price of $55.00 per barrel, we expect cash flows from operations to approximate our capital investments in crude oil and natural gas properties for the year. Although capital investments in crude oil and natural gas properties exceeded cash flows from operations during the nine months ended September 30, 2019, we expect cash flows from operations to exceed capital investments in crude oil and natural gas properties during the fourth quarter of 2019.

In the second quarter of 2019, we completed the Midstream Asset Divestitures for an aggregate cash purchase price of $345.6 million ($263.6 million of which was paid upon closing with $82.0 million to be paid in June 2020), subject to certain customary post-closing adjustments, plus aggregate conditional payments of up to $150.7 million. We allocated $179.6 million of the proceeds to deferred midstream gathering credits for future gathering, processing, transportation and water disposal services. We have and expect to continue to use the proceeds from these divestitures for our capital investment program.

Subject to closing the SRC Acquisition, the borrowing base on our revolving credit facility will increase to $2.1 billion. In addition, we elected to increase the aggregate commitment amount under our revolving credit facility to

Upon closing the SRC Acquisition, we will assume the SRC Senior Notes and be required to pay off and terminate SRC's revolving credit facility. As of September 30, 2019, SRC had $165 million outstanding under its revolving credit facility. The SRC Senior Notes contain a change of control provision pursuant to which, if the consummation of the SRC Acquisition results in a "Change of Control" under the indenture governing the SRC Senior Notes, we will be required to make an offer to repurchase the SRC Senior Notes at a price equal to 101 percent of the principal amount of the notes, together with any accrued and unpaid interest to the date of purchase.

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In April 2019, the Board approved the acquisition of up to $200 million of our outstanding common stock, depending on market conditions. Pursuant to the Stock Repurchase Program, we repurchased 4.4 million shares of outstanding common stock at a cost of $145.5 million from June 2019 through September 2019 and we repurchased 0.3 million shares of outstanding common stock at a cost of $8.9 million during October 2019. Approximately $45.7 million remains available for repurchases under the Stock Repurchase Program as of October 31, 2019. Applicable regulations will prohibit us from repurchasing shares during the period between the distribution of the definitive proxy statement/prospectus relating to the SRC Acquisition and the closing of the acquisition. Additionally, in August 2019, contingent on the closing of the SRC Acquisition, the Board approved an increase and extension to the Stock Repurchase Program. The program now contemplates up to $525 million in repurchases with a target completion date of December 31, 2021.

Operational Overview

We ran three drilling rigs in the Wattenberg Field through mid-September 2019 and then dropped to a two-rig pace, which we expect to maintain during the remainder of 2019. In the Delaware Basin, we ran three rigs through May 2019 and then dropped to a two-rig pace in June 2019. We expect to continue to operate at a two-rig pace in the Delaware Basin throughout the remainder of the year. We were able to reduce the number of rigs in each area primarily due to operational efficiencies, our allocation of our planned expenditures and our inventory of drilled uncompleted wells. The projected activities and results discussed in this section and below in "2019 Operational and Financial Outlook" do not reflect any additional impact of the SRC Acquisition.

The following tables summarize our drilling and completion activity for the nine months ended September 30, 2019:







                                                                      Operated Wells
                                                Wattenberg Field       Delaware Basin            Total
                                                Gross        Net      Gross        Net      Gross      Net
        In-process as of December 31, 2018       133       122.4        18        17.4       151      139.8
        Spud                                     107       102.6        24        23.3       131      125.9
        Turned-in-line                          (102 )     (93.3 )     (21 )     (20.0 )    (123 )   (113.3 )
        In-process as of September 30, 2019      138       131.7        21        20.7       159      152.4
                                                                     Non-Operated Wells
                                                Wattenberg Field         Delaware Basin             Total
                                                Gross        Net       Gross         Net       Gross      Net
        In-process as of December 31, 2018        5           2.0         6           0.9        11       2.9
        Spud                                     46           4.1         3           0.4        49       4.5
        Turned-in-line                          (19 )        (1.1 )      (9 )        (1.3 )     (28 )    (2.4 )
        In-process as of September 30, 2019      32           5.0         -             -        32       5.0
        


Our in-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection. Our drilled uncompleted wells are generally completed and turned-in-line within a year of drilling.

2019 Operational and Financial Outlook

We currently expect our production for 2019 to range between 48 MMBoe to 50 MMBoe, or approximately 132,000 Boe to 137,000 Boe per day. We estimate that approximately 40 percent of our 2019 production will be comprised of crude oil and approximately 22 percent will be NGLs, for total liquids of approximately 62 percent. Our planned 2019 capital investments in crude oil and natural gas properties, which we now expect to be at or near the low end of our $810 million to $840 million range, are focused on continued execution of our development plans in the Wattenberg Field and Delaware Basin.

We believe that our disciplined approach in allocating our planned expenditures allows us to maintain a degree of operational flexibility to control the pace of our capital spending. As we execute our capital investment program, we continually monitor, among other things, cost efficiencies, expected rates of return, the political environment and our remaining inventory in order to best meet our short- and long-term corporate strategy. Should commodity pricing or the operating environment deteriorate, we may determine that an adjustment to our development plan is appropriate.

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Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in the core Wattenberg Field, which we have delineated between the Kersey, Prairie and Plains development areas. Our 2019 capital investment program for the Wattenberg Field is approximately 60 percent of our total capital investments in crude oil and natural gas properties, of which approximately 95 percent is expected to be invested in operated drilling and completion activity. We plan to drill standard-reach lateral ("SRL"), mid-reach lateral ("MRL") and extended-reach lateral ("XRL") wells in 2019, the majority of which will be in the Kersey area of the field. In 2019, we anticipate spudding approximately 120 to 130 operated wells and turning-in-line approximately 110 to 125 operated wells. We expect an average development cost of between $3 million and $5 million per well, depending upon the lateral length of the well. The remainder of the Wattenberg Field capital investment program is expected to be used for land, capital workovers, facilities projects and non-operated drilling.

Delaware Basin. Total capital investments in crude oil and natural gas properties in the Delaware Basin for 2019 are expected to be approximately 40 percent of our total capital investments in crude oil and natural gas properties, of which approximately 85 percent is allocated to spud 33 operated wells and turn-in-line 21 operated wells. We plan to drill MRL and XRL wells in 2019 with an expected average development cost of between $11.5 million and $13 million per well, depending upon the lateral length of the well. We do not plan to drill any SRL wells in the Delaware Basin in 2019. Based on the timing of our operations and requirements to hold acreage, we may elect to drill wells different from or in addition to those currently anticipated as we are continuing to analyze the terms of the relevant leases. We plan to use approximately 15 percent of our budgeted Delaware Basin capital for leasing, non-operated capital, seismic and technical studies and facilities.

Corporate Capital. In 2019, we also expect to spend approximately $20 million for corporate capital, the majority of which is related to the implementation of an Enterprise Resource Planning system to replace our existing operating and financial systems. This long-planned investment is being made to enhance maintenance of our financial records, improve operational functionality and provide timely information to our management team related to the operation of the business.







        Financial Guidance.
        The following table sets forth our current financial guidance for the year ended
        December 31, 2019 for certain expenses and the impact of price differentials,
        exclusive of expected costs related to the SRC Acquisition:
                                                                            Low        High
        Operating Expenses
        Lease operating expenses ($/Boe)                                  $ 2.85     $ 3.00
        Transportation, gathering and processing expenses ("TGP") ($/Boe) $ 0.90     $ 1.00
        Production taxes (% of crude oil, natural gas and NGLs sales)          6 %        7 %
        General and administrative expense ("G&A") ($/Boe)                $ 3.00     $ 3.20
        Estimated Price Realizations (% of NYMEX, excludes TGP)
        Crude oil                                                           90%        95%
        Natural gas                                                         40%        45%
        NGLs                                                                20%        25%
        


In June 2019, in response to current market conditions and reductions in development activity in the Wattenberg Field and Delaware Basin, we instituted measures we believe were necessary to reduce our general and administrative expenses. As a result, we reduced corporate headcount by approximately 15 percent to more closely align with our updated operational plans. These measures have resulted in general and administrative expense, exclusive of costs incurred related to the SRC Acquisition, of $2.84 per Boe in the third quarter of 2019. We expect our general and administrative expense, exclusive of costs incurred related to the SRC Acquisition, to be in the range of $2.60 to $2.80 per Boe for the fourth quarter of 2019.

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Regulatory Update

Senate Bill 19-181. In April 2019, Colorado Senate Bill 19-181 ("SB-181") was signed into law and made a number of changes to oil and gas regulation in Colorado. The bill gives local governments the option to regulate facility siting and surface impacts and increases air quality monitoring and environmental protection. It also changes the mission and makeup of the COGCC, among other things. Rulemakings contemplated by the bill may create new application and operating requirements; however, the rulemaking process is expected to take years to finalize. In October 2019, the CDPHE released a study of potential health risks that modeled certain exposure scenarios at distances up to 2,000 feet, based on data collected at oil and gas development and production sites. The study concluded that modeling results "support increased concern for adverse effects" in a very narrow set of hypothetical circumstances associated with the development phase of oil and gas operations. As a result, the COGCC has determined that it will utilize the objective criteria developed following SB-181 in reviewing proposed permits for locations up to 2,000 feet from building units. The criteria are currently being used in the review of permits up to 1,500 feet from building units. We may experience significant delays in the issuance of permits and necessary approvals as a result, but we have previously been successful in obtaining permits under the objective criteria. We primarily operate in the core Wattenberg Field in Weld County and have approved permits for development into April of 2021; however, significant delays in the issuance of permits could adversely impact the timing of our future development plans in the Wattenberg Field.

Ozone Classification. In 2016, the EPA increased the state of Colorado's non-attainment ozone classification for the Denver Metro North Front Range Ozone Eight-Hour Non-Attainment ("Denver Metro/North Front Range NAA") area from "marginal" to "moderate" under the 2008 national ambient air quality standard ("NAAQS"). This increase in non-attainment status triggered significant additional obligations for the state under the Clean Air Act ("CAA") and resulted in Colorado adopting new and more stringent air quality control requirements in November 2017 that are applicable to our operations. Ozone measurements in the Denver Metro/North Front Range NAA exceeded the NAAQS during 2018, subjecting it to a further reclassification to "serious." In 2018, the CDPHE requested an extension to the "serious" ozone classification as a result of a year of compliant ozone monitoring in 2017. This extension request was withdrawn by Governor Polis in March 2019. The EPA and CDPHE are currently determining the process for a "serious" designation, which is expected to occur later this year. A "serious" classification will trigger significant additional obligations for the state under the CAA and could result in new and more stringent air quality control requirements, which may in turn result in significant costs, and delays in obtaining necessary permits applicable to our operations.

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                                        PDC ENERGY, INC.
        Results of Operations
        Summary Operating Results
           The following table presents selected information regarding our operating
                                            results:
                                                Three Months Ended September 30,                   Nine Months Ended September 30,
                                            2019             2018        Percent Change        2019            2018        Percent Change
                                                                   (dollars in millions, except per unit data)
        Production
        Crude oil (MBbls)                    4,853            4,296            13.0  %        14,277           12,040            18.6  %
        Natural gas (MMcf)                  29,273           21,765            34.5  %        83,916           62,040            35.3  %
        NGLs (MBbls)                         2,983            2,177            37.0  %         8,091            6,010            34.6  %
        Crude oil equivalent (MBoe)         12,714           10,100            25.9  %        36,354           28,390            28.1  %
        Average Boe per day (Boe)          138,195          109,783            25.9  %       133,165          103,993            28.1  %
        Crude Oil, Natural Gas and NGLs
        Sales
        Crude oil                       $    255.7       $    284.7           (10.2 )%     $   761.0       $    763.7            (0.4 )%
        Natural gas                           26.6             34.7           (23.3 )%         110.1            103.4             6.5  %
        NGLs                                  25.1             53.0           (52.6 )%          96.4            136.5           (29.4 )%
        Total crude oil, natural gas
        and NGLs sales                  $    307.4       $    372.4           (17.5 )%     $   967.5       $  1,003.6            (3.6 )%
        Net Settlements on Commodity
        Derivatives
        Crude oil                       $     (1.9 )     $    (51.6 )         (96.3 )%     $   (19.5 )     $   (104.1 )         (81.3 )%
        Natural gas                            3.7              4.8           (22.9 )%          (0.3 )           18.7          (101.6 )%
        NGLs                                     -             (1.3 )             *                -             (5.1 )             *
        Total net settlements on
        derivatives                     $      1.8       $    (48.1 )        (103.7 )%     $   (19.8 )     $    (90.5 )         (78.1 )%
        Average Sales Price (excluding net settlements on
        derivatives)
        Crude oil (per Bbl)             $    52.70       $    66.27           (20.5 )%     $   53.30       $    63.43           (16.0 )%
        Natural gas (per Mcf)                 0.91             1.60           (43.1 )%          1.31             1.67           (21.6 )%
        NGLs (per Bbl)                        8.43            24.35           (65.4 )%         11.92            22.71           (47.5 )%
        Crude oil equivalent (per Boe)       24.18            36.88           (34.4 )%         26.61            35.35           (24.7 )%
        Average Costs and Expenses (per
        Boe)
        Lease operating expenses        $     2.87       $     3.27           (12.2 )%     $    2.92       $     3.34           (12.6 )%
        Production taxes                      1.03             2.37           (56.5 )%          1.59             2.35           (32.3 )%
        Transportation, gathering and
        processing expenses                   0.87             0.91            (4.4 )%          0.95             0.90             5.6  %
        General and administrative
        expense                               3.23             4.78           (32.4 )%          3.40             4.27           (20.4 )%
        Depreciation, depletion and
        amortization                         13.52            14.61            (7.5 )%         13.53            14.44            (6.3 )%
        








        Lease Operating Expenses by Operating Region
        (per Boe)
        Wattenberg Field                $     2.51       $     3.01           (16.6 )%     $    2.53       $     3.11           (18.6 )%
        Delaware Basin                        3.94             4.09            (3.7 )%          4.21             4.13             1.9  %
        Utica Shale (1)                          -                -               *                -             3.46               *
        


Amounts may not recalculate due to rounding.

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                                        PDC ENERGY, INC.
        Crude Oil, Natural Gas and NGLs Sales
        For the three and nine months ended September 30, 2019, crude oil, natural gas
        and NGLs sales revenue decreased compared to the three and nine months ended
        September 30, 2018 due to the following:
                                                      Three Months Ended September     Nine Months Ended September
                                                                30, 2019                        30, 2019
                                                                              (in millions)
        Increase in production                        $                 68.6          $                225.6
        Decrease in average crude oil sales price                      (65.9 )                        (144.6 )
        . . .
        


Nov 07, 2019

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