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where we standwhere we are going
2018 Heikkinen Energy Conference
August 15, 2018
Forward-Looking Statements and Other Disclaimers
2
This presentation includes forward‐looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended. The statements regarding future financial and operating performance and
results, strategic pursuits and goals, market prices, future hedging and risk management activities, and other statements that are not historical
facts contained in this report are forward-looking statements. The words “expect”, “project”, “estimate”, “believe”, “anticipate”, “intend”, “budget”,
“plan”, “forecast”, “outlook”, “target”, “predict”, “may”, “should”, “could”, “will” and similar expressions are also intended to identify forward-looking
statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including geographic
basis differentials) of natural gas and crude oil, results of future drilling and marketing activity, future production and costs, legislative and
regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed herein and in our other Securities and Exchange
Commission (SEC) filings. See “Risk Factors” in Item 1A of the Form 10-K and subsequent public filings for additional information about these
risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual
outcomes may vary materially from those indicated. Any forward-looking statement speaks only as of the date on which such statement is
made, and Cabot Oil & Gas (the “Company” or “Cabot”) does not undertake any obligation to correct or update any forward-looking statement,
whether as the result of new information, future events or otherwise, except as required by applicable law.
This presentation may contain certain terms, such as resource potential, risked or unrisked resources, potential locations, risked or unrisked
locations, EUR (estimated ultimate recovery) and other similar terms that describe estimates of potentially recoverable hydrocarbons that the
SEC rules prohibit from being included in filings with the SEC. These estimates are by their nature more speculative than estimates of proved,
probable and possible reserves and may not constitute “reserves” within the meaning of SEC rules and accordingly, are subject to substantially
greater risk of being actually realized. These estimates are based on the Company’s existing models and internal estimates. Actual locations
drilled and quantities that may be ultimately recovered from the Company’s interests could differ substantially. Factors affecting ultimate
recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, drilling and
production costs, availably of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals,
actual drilling results, including geological and mechanical factors affecting recovery rates, and other factors. These estimates may change
significantly as development of the Company’s assets provide additional data. Investors are urged to consider carefully the disclosures and risk
factors about Cabot’s reserves in the Form 10‐K and other reports on file with the SEC.
This presentation also refers to Discretionary Cash Flow, EBITDAX, Free Cash Flow, Adjusted Net Income (Loss), Return on Capital Employed
(ROCE) and Net Debt calculations and ratios. These non-GAAP financial measures are not alternatives to GAAP measures, and should not be
considered in isolation or as an alternative for analysis of the Company’s results as reported under GAAP. For additional disclosure regarding
such non-GAAP measures, including definitions of these terms and reconciliations to the most directly comparable GAAP measures, please
refer to Cabot’s most recent earnings release at www.cabotog.com and the Company’s related 8-K on file with the SEC.
Q2 2018 Highlights
3
• Daily equivalent production of 1,895
Mmcfe per day
• Net income of $42.4 million (or $0.09 per
share); adjusted net income (non-GAAP)
of $57.9 million (or $0.13 per share)
• Net cash provided by operating activities
of $273.9 million; discretionary cash flow
(non-GAAP) of $196.5 million
• Returned $239.6 million of cash to
shareholders through dividends and
share repurchases
• Improved operating expenses per unit by
eight percent relative to the prior-year
quarter
• Announced increase in share
repurchase authorization by 20.0
million shares, bringing the current
remaining authorization to 30.1 million
shares
Note: See supplemental tables at the end of the presentation for a reconciliation of non-GAAP measures1 Includes direct operations, transportation and gathering, taxes other than income, exploration, DD&A, general and administrat ive, and interest expense
Q2
2018
Q1
2018
Q2
2017
Equivalent Production (Mmcfe/d) 1,895 1,884 1,902
Realized Gas Price (Incl. Hedges) ($/Mcf) $2.15 $2.44 $2.38
Realized Gas Price (Excl. Hedges) ($/Mcf) $2.11 $2.50 $2.38
Net Income ($mm) $42.4 $117.2 $21.5
Adjusted Net Income (non-GAAP) ($mm) $57.9 $128.5 $64.0
Discretionary Cash Flow (non-GAAP) ($mm) $196.5 $280.3 $255.7
EBITDAX (non-GAAP) ($mm) $232.1 $278.6 $274.4
Operating Expenses1 ($/Mcfe) $1.85 $1.58 $2.02
LTM Net Debt / EBITDAX (Non-GAAP) 0.8x 0.5x 1.1x
Cabot Oil & Gas Overview
4
• 2017 Year-End Proved Reserves: 9.7 Tcfe (13% year-over-year increase)
• 2017 Production: 1,878 Mmcfe/d (10% year-over-year increase)
• 2018E Production Growth: 10% - 12%
• 2018E Capital Expenditures: $960 million
~3,000 Remaining Undrilled Locations
Year-End 2017 Net Producing Horizontal Wells: 561
2018E Wells Placed on Production: 80 Net Wells
Inventory Life Based on 2018E Activity: ~35 years
MARCELLUS SHALE
Proven Track Record of Debt-Adjusted per Share Growth
5
2011 2012 2013 2014 2015 2016 2017
Daily Production Per Debt-Adjusted Share
2011 2012 2013 2014 2015 2016 2017
Year-End Proved Reserves Per Debt-Adjusted Share
Note: Debt-adjusted share count is calculated as the sum of the annual weighted average shares outstanding plus the incremental “debt shares” by dividing total debt by the average
annual share price.
Industry-Leading Cost Structure Continues to Improve…
6
$1.21
$0.87
$0.55
$0.71 $0.57
$0.37 $0.35
2011 2012 2013 2014 2015 2016 2017
Total Company All-Sources Finding & Development Costs ($/Mcfe)
Marcellus All-Sources Finding & Development Costs ($/Mcf)
$0.65
$0.49
$0.40 $0.43
$0.31 $0.26
$0.22
2011 2012 2013 2014 2015 2016 2017
…Resulting in a Continued Reduction in Breakeven Prices
7
$1.88
$1.74
$1.31 $1.30 $1.30
$1.16 $1.13$1.06
$0.99
2011 2012 2013 2014 2015 2016 2017 Q1 2018 Q2 2018
Operating Transportation¹ Taxes O/T Income Cash G&A² Financing³ Exploration
1 Includes all demand charges and gathering fees
2 Excludes stock-based compensation
3 Excludes non-cash interest expense associated with income tax reserves and amortization of deferred financing cost
4 Excludes dry hole cost
Cash Operating Expenses ($/Mcfe)
4
Cabot’s Balance Sheet is Well-Positioned to Provide Financial Flexibility Through the Commodity Price Cycle
8
1.4x 1.4x
0.9x
1.2x
2.5x
1.8x
1.0x
0.5x
0.8x
2011 2012 2013 2014 2015 2016 2017 Q1 2018 Q2 2018
Target Leverage Ratio:
1.0x – 1.5x
Note: See supplemental tables at the end of the presentation for a reconciliation of non-GAAP measures
Net Debt to LTM EBITDAX
Cabot Oil & Gas Strategy
9
Deliver growth in production and
reserves per debt-adjusted share while
generating positive free cash flow
Generate an improving return on
capital employed (ROCE) that
exceeds our cost of capital
Increase the return of capital to
shareholders through dividends
and share repurchases
Maintain a strong balance sheet
to maximize financial flexibility
• 20%+ CAGR in production and reserves per debt-adjusted share from
2011 – 2017
• Three-year plan production CAGR of 17% - 21% (20% - 24% on a
divestiture-adjusted basis)
• Forecasted cumulative free cash flow of $1.6 bn - $2.5 bn from 2018 – 2020
allows for potential share repurchases and/or debt reduction, furthering
enhancing debt-adjusted per share growth
• Anticipate ROCE increasing from 7.3% in 2017 to 18% - 23% by 2020
(based on a $2.75 - $3.25 NYMEX price range)
• ROCE would be further enhanced by future share repurchases or debt
reduction
• Returned over $200 mm of capital to shareholders in 2017 and $536 mm
YTD 20181
• Increased dividend by 150 percent in 2017 and 20 percent in 2018
• Repurchased 20 million shares year-to-date 20181
• Increased share repurchase program authorization by 20.0 mm to 30.1 mm
shares (~7% of current shares outstanding)
• Net debt / LTM EBITDAX of 0.8x as of 6/30/2018
• Liquidity of ~$2.4 bn including cash on hand of $741 mm as of 6/30/2018
• Subsequent to 6/30/2018, paid down $237 mm of 6.5% senior notes
Disciplined capital allocation focused on delivering debt-adjusted per share growth,
generating positive free cash flow, improving corporate returns on capital employed,
increasing return of capital to shareholders, and maintaining a strong balance sheet
1 As of July 27, 2018
Note: See supplemental tables at the end of the presentation for a reconciliation of non-GAAP measures
Q1 2018 Q2 2018 Q3 2018E Q4 2018E
~2,100 –
2,2001,884 1,895
2018 Capital Budget and Operating Plan
10
83%
8%
7%2%
Marcellus Shale Exploration Areas
Pipeline Investments Corporate
2018E Production Growth: 10% - 12%
Net Marcellus Wells Placed on Production2018E Total Program Spending: $960 mm
(includes $70 mm of equity pipeline investments)
Net Production (Mmcfe/d)1
0
20
37
23
Q1 2018 Q2 2018 Q3 2018E Q4 2018E
Due to larger pad
sizes in Q1 and the
2nd completion
crew not coming
online until
February 2018, no
wells were placed
on production
during Q1
• Assumes Gen 5 Completion Design Across the Majority of the 2018 Program
• 2018 Drilling Program Average Lateral Length: 8,300 feet
• 2018 Average Well Cost (Including Facilities): $8.3 million ($1,000 per lateral foot)
1 Production forecasts are subject to change based on the in-service timing of new infrastructure projects and takeaway capacity.
2018
exit-to-exit
divestiture-
adjusted
production
growth
guidance:
~35%
Cabot’s Marcellus Position is the Most Prolific U.S. Onshore Natural Gas Resource Play
11
4.4
2.9
Appalachian Gas Play
Non-Appalachian Gas Play
Peer Average: 2.17 Bcfe / 1,000’
Estimated Ultimate Recovery (EUR) – Bcfe/1,000 Lateral Feet
Source: Current investor presentations as of February 16, 2018. Peers include Antero Resources, Chesapeake Energy, Eclipse Resources, EQT Corporation, Gulfport Energy, Range Resources, and Southwestern Energy. For companies with multiple type curves, a weighted average was used based on location count or acreage, based on current allocation of drilling capital.
Based on
Gen 4 / 5
completion
designs
• Based on older Gen 1 / 2 / 3 completion designs
• Represents >70% of the Lower Marcellus EUR
per 1,000 lateral feet for comparable well design
• Plan to test Gen 5 design on a few Upper
Marcellus wells in 2H 2018
2018 is an Inflection Year for Cabot
12
~2.22Bcf/d
2.2 2.4 2.5
3.6~3.75Bcf/d
165 Mmcf/d
160Mmcf/d
1.05 Bcf/d
150Mmcf/d
Q2 2018 GrossProduction
Moxie FreedomPower Plant
(In-service as ofAugust 8, 2018)
Lackawanna EnergyCenter Power Plant
(Train 1 online; Train 2& 3 on schedule for 2H
2018)
Atlantic Sunrise(Target in-service:
Early September 2018due to weather-related
delays¹)
PennEast(2019)
Future GrossProduction Capacity
Based on FirmTransport / Firm SalesSecured as of Q2 2018
Cabot continues to evaluate new opportunities to increase firm transport capacity / firm sales and remains
confident it can organically grow its production base above 3.75 Bcf/d through the following opportunities:
1) additional sales on currently approved takeaway projects (i.e. Atlantic Sunrise / PennEast)
2) incremental sales on potential future expansion projects
3) increasing in-basin market share
4) new in-basin demand projects
5) future greenfield takeaway projects (including Constitution Pipeline)
•350 Mmcf/d (COG transport capacity): 20 years
•500 Mmcf/d (COG transport capacity): 15 years
•150 Mmcf/d (3rd party transport capacity): 3 years
•50 Mmcf/d (Long-term firm sales): 15 years
1 As of August 15, 2018Note: COG firm transport capacity / firm sales are stated on a gross basis before royalties
Remaining
capacity
associated with
Trains 2 & 3
Cabot Offers a Compelling Combination of Top-Tier Yield, Free Cash Flow and Growth
13
3.1%
1.2%1.0% 1.0%
0.7% 0.7% 0.5% 0.5%0.2% 0.2% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Peer A Peer B COG Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K Peer L Peer M Peer N Peer O Peer P
Source: FactSet as of 7/25/2018; peers include: AR, CHK, XEC, CXO, CLR, DVN, ECA, EQT, MRO, MUR, NFX, NBL, PXD, QEP, RRC, SWN.
1 Free cash flow yield is calculated as consensus estimates for discretionary cash flow less capital expenditures divided by market capitalization
2 CXO pro forma for RSP Permian acquisition; EQT pro forma for Rice Energy acquisition
Current Dividend Yield
2019E Free Cash Flow Yield1
2017 – 2019E Production CAGR2
8.2%7.1% 7.1%
5.8% 5.8%
3.6% 3.1% 2.6% 2.2% 2.2% 1.9% 1.8% 1.3% 0.6%
(0.6%)(2.0%)
(3.8%)Peer C Peer A Peer G COG Peer M Peer H Peer D Peer I Peer F Peer N Peer L Peer J Peer B Peer E Peer P Peer O Peer K
21.2% 21.0% 20.1% 19.4% 19.1% 18.0%15.3% 14.9% 13.6%
10.6%9.0%
6.2%4.2% 3.4% 2.6%
(0.3%)(3.4%)
COG Peer L Peer J Peer G Peer M Peer N Peer I Peer E Peer H Peer F Peer C Peer P Peer A Peer D Peer B Peer K Peer O
Peer Median: 0.2%
Peer Median: 2.2%
Peer Median: 12.1%
Cabot is Committed to Returning Capital to Shareholders
14
Return of Capital to Shareholders ($mm)
$13 $17$25 $33 $33 $36
$79$109
$165 $139
$124
$481Year-to-
Date (as of
July 27,2018)
$0
$100
$200
$300
$400
$500
$600
$700
2011 2012 2013 2014 2015 2016 2017 2018E
Dividends Share Repurchases
Increased
Dividend
33%
Increased
Dividend
100%
Increased
Dividend
150%
Increased
Dividend
20%
Commodity Price
Downturn
Remaining share
repurchase
authorization of
30mm shares1
1 As of July 27, 2018Note: The chart above excludes the Company’s 2016 equity issuance
Three-Year Cabot Oil & Gas Outlook
15
$245
2017 Actual 2018E 2019E 2020E
$2.75 NYMEX $3.00 NYMEX $3.25 NYMEX
Note: See the assumptions slide in the appendix for further detail and definitions.
1 Based on midpoint of production guidance. The CAGRs and improvement in ROCE represented in the arrows above are based on the $2.75 NYMEX case.
Adjusted Net Income ($mm)1 Discretionary Cash Flow ($mm)1
Free Cash Flow ($mm)1
7.3%
2017 Actual 2018E 2019E 2020E
$2.75 NYMEX $3.00 NYMEX $3.25 NYMEX
Return on Capital Employed1
$976
2017 Actual 2018E 2019E 2020E
$2.75 NYMEX $3.00 NYMEX $3.25 NYMEX
$155
2017 Actual 2018E 2019E 2020E
$2.75 NYMEX $3.00 NYMEX $3.25 NYMEX
$1.6 bn - $2.5 bn of estimated cumulative after-tax
free cash flow from 2018 – 2020 to reinvest in
the business and return capital to shareholders
Three-Year Production CAGR: 17% - 21% (20% - 24% on a divestiture-adjusted basis)
Incremental share repurchases and debt reduction would further enhance the
growth of these metrics on a debt-adjusted per share basis and improve ROCE
Best-in-Class Marcellus Capital Efficiency
16
Illustrative Average Annual After-Tax Corporate Free Cash Flow at 3.7 Bcf/d Flat ($bn)
$1.0
$1.2
$1.4
$2.75 NYMEX $3.00 NYMEX $3.25 NYMEX
Implied FCF Yield
Based on Current
Market Cap1:
9%
Implied FCF Yield
Based on Current
Market Cap1:
11%
Implied FCF Yield
Based on Current
Market Cap1:
13%
Average Annual Maintenance Capital: ~$500mm
1 Based on market capitalization as of July 26, 2018
Note: Assumes ($0.35) long-term weighted-average differential to NYMEX
Cabot’s expects to reach 3.7 Bcf/d of gross production in 2020
Cabot management expects to grow volumes above this illustrative 3.7 Bcf/d level by securing incremental firm
transport capacity / firm sales and / or increasing in-basin market share
Cabot would generate $1.6bn - $2.5bn of cumulative after-tax corporate free cash flow from 2018 – 2020 before
reaching this 3.7 Bcf/d level (based on a $2.75 - $3.25 NYMEX price range in 2018 – 2020)
The illustrative annual free cash flow estimates below include the impact of income taxes, corporate overhead, and
interest expense
Cabot’s Anticipated Corporate Returns and Growth Are Competitive Across the Broader S&P 500 Index
17
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20%
30%
40%
50%
60%
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10%
15%
20%
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ROCE 2018E - 2019E EPS Growth
1 COG ROCE and EPS calculations are based on internal estimates. COG’s ROCE is calculated with capital employed net of cash to match the methodology used in the referenced
broker research. NTM ROCE estimates by sector are sourced from Wolfe Research’s report on February 12, 2018 titled “Putting Producer ROCE Targets Into Context”.
Note: FactSet median estimates as of 7/25/2018; excludes the Financials sector due to limited 2019 EBITDA estimates.
COG’s ROCE and EPS Growth Outlook vs. Median Estimates By Sector1
Enterprise
Value /
Consensus
2019E EBITDA
Multiple 7.4x 12.4x
20
18
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10.2x 13.7x 10.3x 11.2x 12.4x 10.1x 18.6x 7.6x 6.3x
18
Appendix
2018 Guidance
19
Full-year 2018 total company daily production growth guidance:
10% - 12%
– 2018 exit-to-exit divestiture-adjusted (Marcellus-only)
production growth guidance: ~35%
– Q3 2018 production guidance: 2,100 – 2,200 Mmcfe/d
2018 total program spending: $960 million
– Marcellus Shale: $800 million
– Exploration Areas: $75 million
– Pipeline Investments: $70 million
– Corporate: $15 million
2018 Marcellus Shale wells placed on production: 80 net wells
2018 income tax rate guidance: 24%
2018 deferred tax rate guidance: 100%+ (The Company expects
to receive a refund in 2018 associated with the recent repeal of
the corporate alternative minimum tax)
Q3 2018E Natural Gas Price Exposure By Index
Fixed Price (~$2.65 per Mcf) 25%
NYMEX (minus ~$0.45) 19%
TGP Z4 – 300 Leg 19%
Leidy Line 16%
Millennium 7%
D.C. Market Area 6%
Dominion 6%
Power Pricing 2%
Note: Fixed price percentages above include volumes associated with
sales agreements that have floor prices. An additional deduct of ~$0.05
per Mcf should be applied to account for fuel use.
Q3 2018E Cost Assumptions ($/Mcfe, unless otherwise noted)
Direct operations $0.08 - $0.10
Transportation and gathering $0.66 - $0.68
Taxes other than income $0.02 - $0.03
Depreciation, depletion and amortization $0.48 - $0.53
Interest expense $0.09 - $0.11
General and administrative ($mm)1 $14 - $16
Exploration ($mm)2 $7 - $9
(1) Excluding stock-based compensation(2) Excluding exploratory dry hole costs; includes exploration
administration expense and geophysical expenses
Financial Position and Risk Management Profile
20
$304
$87$188
$62
$575
$312
$0
$100
$200
$300
$400
$500
$600
2018 2019 2020 2021 2022 2023 2024 2025 2026
Natural Gas (NYMEX) Swaps
Total Volume (Bcf)
Average Price per Mcf
Natural Gas (NYMEX) Basis Swaps
Total Volume - Leidy (Bcf)
Average Price per Mcf (Leidy)
Total Volume – Transco (Bcf)
Average Price per Mcf (Transco)
98.0
$2.87
34.1
($0.68)
10.7
$0.41
As of 6/30/2018 $bn
Cash and Cash Equivalents $0.7
Debt $1.5
Net Debt $0.8
Net Capitalization $2.9
Liquidity $2.4
Net Debt / Capitalization 26.6%
Net Debt / LTM EBITDAX 0.8x
2018 Hedge Position1
Debt Maturity Schedule ($mm) as of 6/30/2018 (Including Weighted Average Coupon Rate)
Capitalization / Liquidity
1As of July 27, 20182Based on the midpoint of the production guidance range
Approximately 36% of Cabot’s forecasted 2018 natural gas
volumes are locked-in
(includes NYMEX swaps and fixed price contracts)2
$237mm
repaid in
July 2018
2018 – 2019 Hedge Summary
21
2018 Natural Gas Swaps
# of Total $/Mcf
Pricing Index Contracts Mcf/Day Fixed Price Duration
LDS NYMEX 26 252,574 $2.93 Feb-18 Dec-18
LDS NYMEX 5 48,572 $3.10 Feb-18 Oct-18
2018 Natural Gas Basis Swaps
# of Total $/Mcf
Pricing Index Contracts Mcf/Day Fixed Price Duration
Leidy 5 48,572 ($0.71) Jan-18 Dec-18
Leidy 5 48,572 ($0.68) Feb-18 Dec-18
2018-2019 Natural Gas Basis Swaps
# of Total $/Mcf
Pricing Index Contracts Mcf/Day Fixed Price Duration
Transco 3 29,143 $0.42 Jan-18 Dec-19
Note: As of July 27, 2018
The table above does not include fixed price deals that cover ~23%
of Cabot’s forecasted 2018 natural gas volumes
Three-Year Outlook Assumptions
22
Three-Year Outlook Assumptions (Slide 15)
• ~($0.50) per Mcf weighted-average basis differential in 2018 and ~($0.35) per Mcf weighted-average basis differential in 2019
and 2020
• ~$850 million of annual total company capital spending in 2019 and 2020 (no investments in equity pipelines in 2019 and
2020 as Constitution is not included in this three-year outlook)
• No capital associated with exploration activity in 2019 and 2020; however, assumes ~$35 million of corporate exploration
expense annually. This assumption is subject to change based on the initial results from the ongoing testing in the
Company’s exploratory areas
• Refinancing of notes at maturity based on current market indications
• For purposes of this illustrative analysis, free cash flow is maintained on the balance sheet (ROCE outlook does not reflect
the benefit of this free cash flow)
• Corporate tax rate between 23% and 24% in 2018 – 2020
• Deferred tax rates dependent on NYMEX price assumptions—100%+ in 2018 for all three price cases; a range of 70% to
100%+ in 2019 and 25% to 50% in 2020
• Service cost inflation of 5%+ annually in 2019 and 2020 (subject to market conditions)
• Cash G&A expense increases of 3% and 4% in 2019 and 2020, respectively
• No change to the current Pennsylvania state Impact Fee
Reconciliation of Net Income to Adjusted Net Income and Adjusted Earnings Per Share
23
EBITDAX Calculation and Reconciliation
24
Net Debt Reconciliation
25
Discretionary Cash Flow and Free Cash Flow Calculation and Reconciliation
26
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